Utility executives face volatile energy markets, skyrocketing fuel prices, and changing federal energy policies. How are utilities benefiting from the turnaround in energy trading?
"for applications by sellers with no generation assets in the ground that are affiliated with generation asset-owning utilities, we will continue to evaluate the affiliate generation owner's market power when evaluating whether to grant market based rate authority for the power marketer." Energy Velocity interprets this statement as implying that FERC would use different standards when evaluating a marketer's position in a control area where it owns capacity versus control areas where it does not. Another interpretation is that if the marketer's affiliates have market power in any market, then that marketer's ability to transact at market-based rates would be denied in every market. If the latter interpretation is used, the dollars at risk are significantly higher than those that we identified here at Energy Velocity.
The transactions that occurred in the first half of 2004 happened at an average rate of $23.76/MWh. To understand the impact of mandating cost-based transactions, we analyzed the system lambda data for 2002 (the most recent complete year of data available for these companies). The average lambda was $16.66/MWh for the first half of 2002, which implies a cost-based rate of $18.33 (if you in-clude a cost-plus adder of 10 percent). This difference suggests a market reduction of 23 percent, or nearly $440 million, for only half a year of transactions. Higher gas prices in 2004 would undoubtedly drive a lower market reduction if 2004 lambda data were available.
Any way you look at it, the FERC ruling denying IOUs the ability to transact at market-based rates is going to impact earnings for at least 64 such utilities-unless, perhaps, they join an ISO. Seemingly, the deck is stacked against non-ISO members-their choice is either to fall in line with FERC's definition of who can sell power at market rates, or to forgo transactions at market-based pricing. After all, what's a few hundred million dollars of earnings among friends?
The inputs for this test as defined by FERC are native load, wholesale load, applicant capacity, market uncommitted capacity, and net uncommitted capacity.
Native load is calculated by taking the month in which the single-hour peak occurred and averaging the daily peaks that occurred in that month. Wholesale load is computed by taking the single-hour peak and subtracting native load. Applicant's uncommitted capacity and market uncommitted capacity equal nameplate capacity plus firm and contract purchases minus operating reserves, native load, and long term non-requirement firm sales. Uncommitted capacity includes the applicant's capacity, all other capacity in the control area, and the lesser of first tier interconnected capacity and simultaneous import capability from that interconnected control area. In the event that the applicant owns capacity in an interconnected control area, the company's remote capacity is allocated transmission capability before any competing capacity. Net uncommitted supply is equal to the total uncommitted capacity in the control area and the first tier interconnects minus the wholesale load.
The applicant passes the test if its uncommitted capacity is less than the net uncommitted capacity.
Wholesale Market-Share Analysis
The inputs for this test as defined by FERC are native load, applicant