§839c Sale of Power

Summary

Federal power sales must follow the preference and priority rules of the Bonneville Project Act of 1937 and use rates set under section 839e. The Administrator must offer power to public bodies, cooperatives, and investor-owned utilities to meet firm regional loads that are above those customers’ firm peaking and energy resources from the year before December 5, 1980 and above other resources they say they will use under contract. Resources already used to serve a firm load are treated as still being used unless stopped with the Administrator’s OK or because they wear out, are retired, or lost. Contracts with investor-owned utilities can be reduced under the Act. The Administrator can also sell to Federal agencies. Sales are allowed only if the buyer meets the Administrator’s service standards in effect on December 5, 1980 or later revised. Contracts must let the Administrator limit future obligations if he cannot, on a planning basis, get enough power, and must give a reasonable minimum notice before any restriction. Restrictions can apply only when the total of those customers’ firm loads equals or exceeds the firm capability of Federal base system resources, and they cannot cut total entitlements below that federal capability. A “joint operating entity” (formed by two or more public bodies or coops organized before September 22, 2000 whose members were Bonneville customers by January 1, 1999) must be sold wholesale power to meet its members’ regional firm loads; that power can be resold only to the seller’s retail customers, to another regional member of the same joint entity, or as law allows. If a Pacific Northwest utility offers power at its average system cost, the Administrator must buy it and offer the same amount back for resale to that utility’s regional residential customers. That exchange is limited to 50% of the utility’s regional residential load starting July 1, 1980, rising in equal steps to 100% by July 1, 1985 and after. Cost benefits go to the utility’s residential customers in the State, with a special rule for States partly inside the region. A utility may end the deal under agreed terms if a supplemental charge makes the swap costlier. The Administrator may instead buy cheaper replacement power from other sources. The “average system cost” is set by a method developed with the Council, customers, and State regulators and approved by FERC, and it excludes costs for new large single loads, extra out-of-region loads after December 5, 1980, and facilities canceled before starting operation. The Administrator can sell power to existing direct service industrial customers and must offer each such customer an initial long-term contract after December 5, 1980 that matches its 1975 industrial firm-power entitlement. The Administrator cannot sell to new direct service industrial customers, and extra sales to existing ones require a planning finding, cost-effectiveness, Council agreement, and available resources. Any firm-power entitlement from power the Administrator acquired for a customer under section 839d cannot be cut below that amount; unused entitlement first goes to other customers in the same class (public bodies/coops, Federal agencies, direct service industrial, or investor-owned utilities). Surplus power beyond these obligations may be sold under applicable laws. Within nine months after December 5, 1980 the Administrator had to start offering initial long-term contracts to the listed customer groups; each offer lasts one year. Contract effective dates vary by customer type, but utility and industrial contracts cannot take effect earlier than the first day of the tenth month after December 5, 1980. Initial contracts must protect customers’ entitlements during a declared insufficiency so each customer at least gets what it received in the year immediately before the insufficiency, and the Administrator is treated as having sufficient resources to enter those initial contracts.