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Northern Indiana Public Service Co. v. Federal Energy Regulatory Commission

January 29, 1986

NORTHERN INDIANA PUBLIC SERVICE COMPANY, PETITIONER,
v.
FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT; INTERSTATE POWER COMPANY, PETITIONER, V. FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT; IOWA GAS COMPANY, PETITIONER, V. FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT



Petitions for Review of Orders of the Federal Energy Regulatory Commission.

Author: Swygert

Before ESCHBACH and COFFEY, Circuit Judges, and SWYGERT, Senior Circuit Judge.

SWYGERT, Senior Circuit Judge.

Three natural gas distribution companies, Northern Indiana Public Service Company ("NIPSCO"), Interstate Power Company ("Interstate"), and Iowa Gas Company ("Iowa Gas"), petition this court to review three orders*fn1 and denials of petitions for rehearing of those orders*fn2 of the Federal Energy Regulatory Commission ("the Commission") that relate to the Commission's approval of a new rate design for the Natural Gas Pipeline Company of America ("Natural") system.*fn3 NIPSCO complains that the new rate design is not supported by substantial evidence and results in rates that are unjust, unreasonable, and discriminatory. Interstate complains about the Commission's refusal to reopen the record to reevaluate the rate design, and Iowa Gas argues that the Commission should have conducted an investigation into alleged irregularities in Natural's implementation of the new rate design.

This court has jurisdiction to decide these petitions for review pursuant to section 19(b) of the Natural Gas Act ("the Act"), 15 U.S.C. ยง 717r(b) (1982). We affirm the Commission's approval of the new rate design and its refusal to reopen the record. We vacate, however, the Commission's order refusing Iowa Gas' request for an investigation, and we remand for reconsideration.

I

Natural is a major interstate natural gas pipeline company serving markets in Indiana, Iowa, Illinois, and Missouri and is subject to the Commission's jurisdiction under the Act. Natural sells gas to forty-nine wholesale ("jurisdictional") customers under six different rate schedules (e.g., DMQ-1, G-1, E-1, AOR, WS-1, and WS-2).*fn4 These customers are generally intrastate distribution companies that resell the gas to residential and commercial customers at rates regulated by state energy commissions. Of these forty-nine customers, fifteen are large purchasers under the DMQ-1 rate schedule, the rate schedule at issue in this case. These fifteen wholesalers under the DMQ-1 schedule (e.g., Illinois Power Co., Interstate Power Co., Iowa Electric Light and Power Co., Iowa-Illinois Gas and Electric Co., Mississippi River Transportation Corp., North Shore Gas Co., NIGAS, NIPSCO, Peoples Gas, Associated Natural Gas Co., Iowa Gas., Iowa Southern Utilities Co., Nebraska City, Nebraska, Salem, Illinois, and Wisconsin Southern Gas Co.) account for approximately 93% of Natural's sales of natural gas. Only one percent of Natural's sales are to direct industrial customers, known as "non-jurisdictional" customers.

Natural contracts with each of its forty-nine customers to supply them a certain quantity on any particular day. These quantities are known as daily contract quantities, and they reflect the maximum amount of gas that Natural is required to supply to that customer on each day. Customers do not necessarily buy their full contract quantity every day, and they are not charged the full amount for gas for which they have contracted unless they purchase it. Because the demand for gas in Natural's service area is temperature sensitive, Natural's customers ordinarily purchase their daily contract quantity (or close to it) in the winter months (peak days), but purchase much less during the summer months.

In addition to contracting with Natural to supply gas service, each customer is required to provide Natural with the daily quantity entitlements and monthly quantity entitlements they want from Natural over the next three years. Entitlements are a concept developed as part of Natural's curtailment plan. In the early 1970's, Natural's supplies were inadequate to meet the needs of its customers. A curtailment plan was developed as Sections 22 and 23 of Natural Gas' General Terms and Conditions of its Gas Tariff. Under those sections, Natural's customers "nominate" their expected daily and monthly gas purchases for a twelve-month period beginning April 1. These are known as daily and monthly entitlements. The sum of the monthly entitlements is known as a customer's annual entitlement and can be no greater than 365 times the customer's daily contract demand. Each customer's Basis Annual Quantity is an annual amount that is used in the allocation of each DMQ-1 customer's share of any curtailment imposed by Natural. It is an amount negotiated by Natural and the customer based on that customer's end user profile. It is intended to reflect the amount of gas that each customer believes that "it can live with" on an annual basis.

Natural determines what it expects to be able to deliver of the amounts requested and files this with the Commission. Pursuant to Article 22.31 of the Tariff, if Natural projects daily and monthly deliverability sufficient to meet its total system nominations, each of Natural's customers receives the daily quantity and monthly entitlement which it has requested. And, if Natural can satisfy all nominations, then the allocation provisions of section 22 are not applied. Under the curtailment plan, Natural may reduce the requested nominations only when its projected gas supplies will be less than the total volumes requested by its customers. Only the first year's nomination is binding on the customer. Because of the abundance of gas available, Natural has not implemented any type of curtailment since the late 1970's, and Natural predicts that curtailment will not occur until 1990.

NIPSCO, Interstate, and Iowa Gas and the various intervenors in this action, Peoples Gas Light and Coke Company ("Peoples"), North Shore Gas Company ("NSG"),*fn5 Northern Illinois Gas Company ("NIGAS"), Iowa Gas, and Natural,*fn6 are, except for Natural, local distribution companies which purchase all or part of their natural gas supplies for resale from Natural. NIPSCO serves both residential and industrial customers in the northern one-third of Indiana. Interstate provides gas distribution services to customers (primarily one large industrial customer) in Illinois, Iowa, and Minnesota. Iowa Gas serves mostly residential and small commercial customers in central and southwest Iowa. People sells gas exclusively within the City of Chicago, and Northern Illinois serves the remaining portion of northern Illinois.

This case involves a challenge to a rate design adopted by the Commission. Under the Commission's traditional ratemaking practice, a pipeline is permitted to recover in its rates its costs of service, including a reasonable rate of return on its investment. Hence, the pipeline's total cost of providing service to its customers plus a reasonable rate of return on its investment must first be determined. In this case, there is no dispute concerning the amount of Natural's cost of service plus a reasonable return on investment.

Once the cost of service is established, rates must be set to recover that cost from the pipeline's customers. These rates are ordinarily determined by a four-step process: (1) cost functionalization; (2) cost classification; (3) cost allocation; and (4) rate design. Cost functionalization consists of separating the pipeline's cost by the major function performed by the pipeline system: production and gathering, storage, and transmission. Cost functionalization is not an issue in this appeal.

After the costs have been divided by function, the next step is to classify the costs as fixed or variable. Fixed costs are generally considered to be related to customer demand for capacity which does not vary with the changes in the throughput of the system while variable costs are generally associated with the annual delivery and sale of gas. As a second part of the classification process, fixed and variable costs are classified as either demand or commodity.

Costs classified as demand are generally associated with a pipeline's fixed costs, i.e., those costs incurred for providing peak day service; costs classified as commodity are associated with the volume of gas consumed by each customer.*fn7 Historically, production and gathering fixed costs have been classified to the commodity component because such costs are related to the acquisition of gas supply. In the instant case, the Commission ruled that these production and gathering fixed costs should continue to be classified to the commodity component, and no party has objected to this ruling or to any other aspect of the cost classification process.

The next step, cost allocation, apportions the cost of service between jurisdictional and non-jurisdictional customers and also determines the cost responsibility between classes of jurisdictional customers. In the past, the allocation of the demand costs has been based on the average of the sustained three-day system peak demand. Commodity costs have been allocated on the basis of the annual use of the system. The allocation procedure can also be used, as in this case, to determine cost responsibility between jurisdictional customers in the same class and may be referred to as the rate design process.

The last step, the step at issue in this case, is rate design, the process by which costs are allocated to jurisdictional customers and translated into unit charges.*fn8 Commodity costs are recovered by a per million cubic feet (mcf) charge that it paid by all customers on the basis of the amount of gas they actually use (annual use); demand costs are recovered by a fixed monthly demand charge (imposed whether or not any gas is actually taken) paid by only those customers who have a contractual right to demand certain quantities of gas.

Demand charges are felt differently by high load and low load factor customers.*fn9 Low load factor customers are those distribution companies that service primarily commercial and residential customers whose needs fluctuate considerably between the winter and summer months. As a result of these fluctuations, the proportion these particular distribution companies pay in demand charges is high compared to their commodity charges.

By contrast for high load factor customers, those who receive a relatively steady supply over the year, the demand component of their overall cost of gas is proportionately less. The high load factor customers' needs do not tend to fluctuate either because they provide service to industrial users not subject to weather-related variations or because they have constructed storage facilities which they use to service customers in the winter months. Thus, any shift in costs towards the demand component increases (relatively) the burden borne by low load factor customers; any shift towards the commodity component increases the burden borne by the high load factor customers. In this case, it is essentially the high load factor customers (NIPSCO, ...


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