Some Generators Are Owed Refunds
“Network upgrades” are improvements that had to be made to the grid to accommodate another power plant.
The good news for generators is that the Federal Energy Regulatory Commission is willing to alter existing contracts to require such refunds.
An independent power project signs an “interconnection agreement” with the local utility agreeing to terms under which the project will be allowed to connect its power plant to the utility grid so that it can move its electricity to market. Such contracts require the generator not only to pay for any radial lines, circuit breakers and other costs of the “direct” intertie to connect to the grid, but may also require the generator to advance funds for any network upgrades that will also be needed to accommodate another power plant. Current Federal Energy Regulatory Commission policy is that the costs of network upgrades are not the responsibility of the generator, but instead should be borne by all users of the transmission grid. A utility may require an independent generator to advance the funds for network upgrades, but the amounts must be repaid over time through “transmission credits.”
The bad news is that so far, the only situations where FERC has modified contracts entered into before the new FERC policy to require refunds of network upgrade costs are those where the contract has language allowing either party unilaterally to ask FERC to modify the rates the utility is allowed to charge for transmission.
In 2001, as part of an effort to reduce impediments to the construction of new power plants, FERC adopted a policy that allocated the cost of improvements to the network necessitated by the addition of a new generator – so called “network upgrades”– to all transmission customers, rather than solely to the generator, as long as the new or upgraded facilities become part of the utility grid. Previously, and still, the cost of equipment that benefits only the generator, such as the line that ties a power plant to a transmission grid, must be borne by the generator.
Before 2001, FERC had used a “but for” test for determining what costs must be borne by the generator. Under this test, any costs that the utility would not have incurred “but for” the request by the generator to connect his plant to the grid would have to be borne by the generator.
Under the new policy, the cost of network upgrades that benefit all users of the grid are rolled into the rate base that the utility uses to calculate its transmission rates. The utility must return any amounts it collects from a generator for network upgrades through “transmission credits.” This means that the utility allows the generator to claim the amounts as an offset against future transmission charges for wheeling its electricity across the grid. However, since many generators transfer title to the power they produce before it reaches the grid, the credits can usually be transferred to the customer, or the generator can opt to have the amounts refunded over time in cash. Some utilities have proposed transmission credit mechanisms that are nothing more than a plan to return the money over a few years in cash.
Originally, FERC did not require that interest be added to the amount of the transmission credits, but in response to complaints from generators, it now includes interest calculated at a FERC rate.
The effect of FERC’s new policy is to require generators to finance, but ultimately not to bear, the costs of network upgrades. FERC explains its policy as an extension of its long-established “or” pricing policy, which permits utilities to charge users of its grid either average embedded cost rates or incremental cost rates, but not both. (Interestingly, FERC orders do not discuss the logical policy of requiring the party with the lower cost of capital initially to bear the carrying cost of the new equipment, which would be the most economically efficient approach.)
In a recent decision involving power plants developed by subsidiaries of Duke Energy and interconnected to the Entergy transmission system, FERC clarified its policies on how it determines whether equipment is part of the direct intertie or a network upgrade. First, FERC confirmed that it will treat all equipment at or beyond the point where the generator connects to the grid as network upgrades. In the Duke Energy cases, the network upgrades included a new, high voltage, 500 kilovolt switch station, upgraded circuit breakers, upgrades to transmission lines and substations, all located on the utility side of the interconnection point for the Duke power plants.
The Duke cases were complicated by the fact that, in accordance with prior FERC policy, Duke had signed interconnection agreements with Entergy that assigned the costs of all the equipment, including equipment that FERC now defines as network upgrades, to the generator rather than to the general body of transmission customers. Moreover, in what has become known as the “Hinds I” decision, FERC ruled initially that the parties were bound to the terms of their interconnection agreement and said the contract could only be changed if it were found adversely to affect the “public interest.”
However, FERC later reconsidered its decision. In “Hinds II,” it ruled that the interconnection contracts could and should be modified to conform to FERC’s new policy of allocating the cost of network upgrades to all transmission customers, thus making available its favorable policies even to generators that had previously agreed to arrangements reflecting FERC’s prior pricing policies.
Longstanding US Supreme Court interpretations of the Federal Power Act have left the door open for FERC to modify contracts where necessary to ensure that FERC-jurisdictional power sale and transmission rates are “just and reasonable.” The court has held that where parties to a contract reserve the right unilaterally to request FERC to change a contractually-established rate, then FERC will review the proposed change under its normal standard, which is the same as that used for its initial review of rates, to determine if they comply with existing FERC policies. However, if the parties have waived their right to seek FERC review of their contract and have included so-called “Mobile-Sierra” terms (based on the names of two Supreme Court cases), then FERC will only consider requested changes to the rate if the proposed changes are necessitated by the public interest – for example, where the rate is so low that it would bankrupt the utility that agreed to charge the low rate. This is a much higher hurdle.
The contracts that Duke had with Entergy contained contractual language permitting either party to make a unilateral application to FERC for a change in the rates or other terms or conditions of the contract. As a result, FERC agreed with Duke that the lower “just and reasonable” standard for considering modification of the interconnection contract should be used, rather than the “public interest” standard that some courts of appeal have characterized as “practicably insurmountable.” Since FERC found the allocation of network costs to the independent power project rather than to all grid users to be unjust and unreasonable, it ordered the contracts to be modified to reflect its current transmission cost allocation cost policies.
FERC later cited the “Hinds II” decision to require similar changes to an existing interconnection agreement between a subsidiary of Calpine Corporation and the Pacific Gas & Electric Company. Eleven Calpine subsidiaries reached agreements with PG&E that conform to the FERC’s new policies requiring all transmission customers to pay the costs of network upgrades. However, a 12th subsidiary, the Delta Energy Center, had previously submitted its interconnection agreement to FERC and said in the filing that Delta’s entitlement to credit for the cost of network upgrades resulting from its operations would turn on FERC’s decision in the Duke Energy Hinds case. FERC review of Delta’s contract showed that, like Duke Hinds, Delta had reserved the right to seek unilateral changes to its contract. The agency held that failure to provide Delta with credit for the network upgrades it would initially pay for would be inconsistent with FERC policy and, therefore, would not be just and reasonable. It ordered a change in the contract.
There are a number of implications from these decisions.
Any generator negotiating a new interconnection agreement should make sure that the agreement conforms to FERC’s interconnection policy, which states that all upgrades beyond the point of interconnection are network upgrades the costs of which are the ultimately responsibility of the utility and its transmission customers.
As to contracts entered into prior to the FERC’s new policy initiatives on interconnection, based on these FERC decisions, it is clear that any similarly situated generator – that is, a generator who agreed to bear the costs of what FERC now classifies as network upgrades and whose interconnection agreement expressly reserved its rights to seek unilateral FERC changes to its contract – will be accorded the same treatment. What is not clear is the prospect for convincing FERC to change the cost allocation in interconnection agreements where the generator waived its rights to seek unilateral FERC modification. Generators in such cases must satisfy the higher “public interest” standard to have a contract modified.
Ironically, many independent power companies favor having FERC maintain a “nearly insurmountable” standard against changing long-term power purchase agreements for the sale of electricity at a specified rate not subject to requests for unilateral rate changes. Utilities and California have tried to set aside contracts to buy electricity that were signed when electricity prices were high. If FERC were to establish a lower standard for contract modification of this type of contract in the transmission arena, the decision would haunt generators in their roles as power sellers.