Utility executives face volatile energy markets, skyrocketing fuel prices, and changing federal energy policies. How are utilities benefiting from the turnaround in energy trading?
Mitigating "Mandated" Rate Hikes
How to develop balanced revenue-backed financing to manage the impacts of governmental mandates.
its logical conclusion, not only reducing the cost of capital, but improving leverage as well. Typically, the overall tax-adjusted cost of capital of merchant-generating plants is in the percentage of low to mid-20s. RBF can reduce this cost to about 7 percent at 100-percent debt financing and 10 percent if 20-percent equity still is retained in capital structure. In either case, the cost of the mandated project significantly is reduced by RBF.
Wires and POLRs
Default service responsibility is another mandate being placed on utilities in retail-choice states that may be implicit in other states. This mandate requires the utility, often with no generating facilities of its own, to meet electricity needs for customers not served by other load-serving entities. Regulators, wanting to protect the customers that are not active in the competitive market from volatile prices have at times further mandated that this electricity be provided at a known price.
A common approach being used to meet this mandate is annual or bi-annual supply auctions. Unfortunately, this requires that the utility buy power through the short-term futures market for electricity. Even in the well-organized PJM marketplace, research has found these markets to be extremely inefficient, charging huge risk premiums in the annual range of 10 to 15 percent over the spot market price, possibly a 5 to 7.5 percent increase in overall rates.
A relatively simple solution is for regulators to do away with these inefficient auctions and instead require or allow utilities to purchase all or most of their default-service power needs on the spot market. To protect customers from price volatility often associated with the wholesale electric spot market, these utilities should be allowed or required to establish an annual or bi-annual set of rates for these customers (or at least smaller customers) based upon forecasted spot prices and create a volatility protection fund.
The volatility protection fund (VPF) is a pot of money used to smooth out the costs experienced in the wholesale spot market. It is a self-insurance product that is much cheaper than the premiums for market-offered price hedges. The VPF can be created by issuing revenue-backed financing for the amount that is needed to smooth out volatility. The interest on the VPF would need to be secured by a dedicated revenue stream. Conservatively, the initial VPF might be 20 percent of the projected annual default service electricity purchase. When rates are higher than the actual cost, deposit the extra proceeds in the fund. When rates are lower than actual costs, take money from the VPF and pay the wholesale electricity bill. Balances in the fund could earn interest to reduce the cost of maintaining the VPF.
The cost savings can be enormous. Rather than paying an enormous premium for a short-term price hedge of around 10 to 15 percent, the cost of price stability could be less than 1 percent of the commodity cost of electricity. The efficiency of the marketplace is blended with an RBF to create balance. Both the utility and the customer are protected from market volatility and the customer gets the