Sithe/Independence Power Partners v. F.E.R.C.

• Decision Date: 09 April 2002
• Docket Number: No. 00-1092.,00-1092.
• Citation: 285 F.3d 1
• Parties: SITHE/INDEPENDENCE POWER PARTNERS, L.P., Petitioner v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent Public Service Commission of the State of New York, et al., Intervenors
• Court: U.S. Court of Appeals — District of Columbia Circuit

Page 1

285 F.3d 1

SITHE/INDEPENDENCE POWER PARTNERS, L.P., Petitioner v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent Public Service Commission of the State of New York, et al., Intervenors

No. 00-1092.

United States Court of Appeals, District of Columbia Circuit.

Argued February 8, 2002.

Decided April 9, 2002.

On Petition for Review of Orders of the Federal Energy Regulatory Commission.

Richard P. Bress argued the cause for petitioner. With him on the briefs were David L. Schwartz and Minh N. Vu.

Beth G. Pacella, Attorney, Federal Energy Regulatory Commission, argued the cause for respondent. With her on the brief were Cynthia A. Marlette, Acting General Counsel, and Dennis Lane, Solicitor.

Elias G. Farrah, Rebecca J. Michael and Arnold H. Quint were on the brief for intervenors New York Independent System Operator, Inc. and New York Transmission Owners.

Before: EDWARDS and SENTELLE, Circuit Judges, and SILBERMAN, Senior Circuit Judge.

Opinion for the Court filed by Senior Circuit Judge SILBERMAN.

SILBERMAN, Senior Circuit Judge:

Sithe petitions for review of two orders by the Federal Energy Regulatory Commission, one conditionally accepting a proposal to restructure wholesale electricity sales and transmission services in New York State, the second denying Sithe's application for rehearing. Because FERC failed to explain adequately its decision to depart from its longstanding cost-causation principle in approving a component of the proposal, we grant Sithe's petition for review in part.

I.

Sithe describes itself as a non-utility generator that owns and operates an electric generation facility in New York. Its facility interconnects with the utility Niagara Mohawk Power Corporation's transmission system. Petitioner sells energy, on a wholesale basis, to Niagara and Consolidated Edison Company of New York, Inc. under privately negotiated power purchase agreements. Sithe challenges the Commission's approval of new tariff provisions governing charges for socalled transmission losses. In Order 888,¹ FERC generally required each public utility to file tariffs for open access transmission services to remedy undue discrimination in access to their monopoly-owned transmission wires and required certain power pools, including the New York Power Pool (comprising eight utilities, including Niagara and Con Ed, referred to as the "Member Systems"), to file reformed pooling agreements by December 31, 1996. Under the Order, open access transmission tariffs were to contain at least equivalent terms and conditions for non-discriminatory service to those set out in a Commission-prescribed pro forma tariff. It also encouraged the formation of independent system operators (ISOs) to administer transmission services and new markets for wholesale electricity transactions. These ISOs were to adopt transmission (and ancillary services) pricing policies to promote the efficient use of, and investment in, generation, transmission, and consumption. In response, the Member Systems filed a proposal to replace the existing New York power pool structure with a newly created ISO: the New York Independent System Operator. According to the proposal, the NYISO would be an independent, non-profit administrator of transmission services and of the new markets for wholesale electricity transactions in New York — the accompanying tariff was intended to provide a single open access tariff over the entire New York State transmission system.

This case involves the propriety of the Member Systems' proposed transmission services pricing, specifically the pricing for transmission losses. Transmission losses refer to the amount of electric energy lost when electricity flows across a transmission system: it is a function of the square of the amount of the current flowing on the wire and of the resistance it encounters. In general, the current on a given transmission line remains a constant, and the loss associated with a single transmission of electricity is primarily a function of the distance the electricity is transmitted. Northern States Power Co. (Minn) v. FERC, 30 F.3d 177, 179-80 (D.C.Cir.1994). Utilities (who control the transmission lines) must deliver to the electricity customer the entire amount contracted for, regardless of the inevitable loss, so a transmission customer (an entity such as Sithe who pays a utility to transmit electricity across its lines) generally compensates a utility for lost energy either by providing more energy at the injection point than the electricity customer receives at the withdrawal point, or by providing energy in-kind to the transmitting utility.

The Member Systems propose tariffs that would charge transmission customers for transmission losses predicted on a "locational based marginal pricing" (LBMP) method, which would take into account costs imposed by congestion on the system. As its name implies, the methodology has both a marginal and a locational element. We gather from the parties' submissions that it predicts costs taking into account location, because the efficiency of a given electricity withdrawal or injection location may depend on the relative crowedness of a transmission route at that time. It also projects costs on the margin, meaning that it takes into account how much electricity is already on the system when an additional unit is added, because the more electricity on the system at a given time the higher the costs. For example, in the event of ten consecutive transactions each adding one unit of electricity to the system, the tenth transaction imposes a greater cost than the first additional unit. The parties do not make clear whether the LBMP method also includes traditional cost factors such as the distance load traveled. Previously, losses had been calculated using either a "rolled-in" rate or through modeling techniques that allocated charges to each transmission customer based on average (or approximate) system-wide costs imposed by the addition of load. When utilities allocated losses through a "rolled-in" average system transmission loss factor, system-wide losses were divided pro rata, and each customer paid a standard, per-unit amount. Similarly, utilities have previously allocated losses based on their transmission customers' incremental usage, using load flow models and prioritization systems to approximate the marginal losses caused by each transmission customer. The Member Systems asserted that their proposed LBMP-based tariff would be an improvement. It would send efficient price signals to market participants because it could calculate the actual marginal losses transmission customers impose on the system.

But in its tariff, the Member Systems did not propose to rely on a straight LBMP methodology; instead, they added a "simplifying assumption" that is the crux of this case. Every MWH of energy injected into the system is treated as the "last" MWH of energy on the system, and therefore this assumption would lead to the systematic overcollection of the amount of revenue needed to offset the transmission system's actual losses. The record indicates that the overcollection would be as high as 31%. The Member Systems proposed using the excess amounts to offset the NYISO's Scheduling, System Control and Dispatch Service charge (the "Scheduling Charge"), before allocating such costs among transmission customers. Generally, the total Scheduling Charge paid by a particular transmission customer is the product of the Scheduling Charge rate and the amount of power withdrawn by the customer from the system. That rate equals the NYISO's monthly overhead and other costs and expenses, minus certain credits such as overcollections for transmission losses, divided by the total number of billing units in the system. The Member Systems proposed to provide a sort of indirect refund of overcollections to those transmission customers subject to the Scheduling Charge. Unfortunately, as discussed below, FERC has never established that each entity that would be overcharged by the LBMP methodology is subject to and would benefit from a reduced Scheduling Charge.

In relevant part, FERC conditionally accepted the Member...