Data request 17 asks for copies of all MEAG gas purchase contracts. SGNG contends these data are needed to probe Mr. Corbin's competence on SGNG's gas purchase practices and to obtain data relevant to MGAG's proposal to consolidate SGNG and Southern Natural Gas operations, or to restrict SGNG to transportation services.

Data request 17 is plainly irrelevant. As already noted, Mr. Corbin's professional qualifications and expertise can be examined by SGNG under oath during the hearing and argued on brief. Moreover, on motion of SGNG, Mr. Corbin's testimony on the "roll-in" of SGNG and Southern Natural costs and services and the proposal to convert SGNG into transportation services only will be excluded from the record.

The motion to compel a response to data request 17 is denied.

Data request 26 seeks all documents relative to the availability of Rate Schedule G-1 on the SGNG system. SGNG makes no attempt to justify or support this data request, which is vague in the extreme, with a positive showing that the documents sought will lead to relevant evidence not otherwise available to the movant.

The motion to compel MGAG to respond to data request 26 is denied.

Data requests 31 and 32 ask MGAG to furnish the “terms of any gas cost pricing policy” applicable to firm transportation customers, and copies of all documents relative to the. conversion of MGAG customers' sales contract demand to firm transportation. The basis for this request is Mr. Corbin's critical testimony on SGNG's failure to convert sales contract demand with Southern Natural to firm transportation, which SGNG claims is linked to customer service patterns on the SGNG system. MGAG objects to the data requests on the grounds of relevance and confidentiality.

Data requests 31 and 32 are considered generally relevant to the rate issues and the prudency of SGNG's gas purchase practices. MGAG will make available to SGNG for inspection and reproduction the material sought by data requests 31 and 32. With regard to protection for "confidential and commercially sensitive" material, MGAG will identify for the record all such documents and prepare for approval by the presiding administrative law judge a protective order, acceptable to SGNG, that will preserve the integrity of the allegedly privileged information.

The motion to compel MGAG to respond to data requests 31 and 32 is granted.

Data requests 33 and 34 call for MGAG to provide information on increased costs related

FERC Reports

to SGNG's throughput losses and rate discounting as discussed in Mr. Corbin's prepared testimony and which he believes was caused by SGNG operating as an independent pipeline when it is actually a wholly owned subsidiary of Southern Natural. The data requests reference the Corbin testimony that SGNG moved to strike and which will not be received into evidence.

The motion to compel MGAG to respond to data requests 33 and 34 is denied.

Data request 35 is an inquiry into peak day deliveries by MEAG members to customers for five winter seasons from 1985 through 1990, and whether peak day requirements for MGAG members were supplied by firm sales service from SGNG, firm transportation, or peak shaving. SGNG states the data requested is relevant to issues that must be resolved within the framework of the Commission's rate design policy and Mr. Corbin's testimony on the restructuring of SGNG's pipeline operations. See 47 FERC 61,295 (1989); 48 FERC 61,122 (1989); and 54 FERC ¶ 63,020 (February 28, 1991). MGAG objects to the data request mainly on the grounds that data on three-day peak deliveries to MGAG members for the past three years have been served on SGNG and thus, there is no need to furnish SGNG with "information it already possesses."

It is concluded that data request 35 is generally relevant to the rate design issues which the Commission has ordered to be resolved in this proceeding. MGAG is instructed to make available to SGNG the peak day delivery data requested for those MGAG members who are also SGNG customers for the 1987-88, 1988-89 and 1989-90 winter seasons which will coincide with the formation of MGAG in 1987.

The motion to compel MGAG to respond to data request 35 is granted as modified.

Data request 36 asks MGAG, which is a consortium of municipalities formed by the Georgia legislature in 1987 that own and operate natural gas systems, to provide for SGNG the budgets for each of the municipalities for the last five years. These data are needed, asserts SGNG, to prepare a response in anticipation of a MGAG claim that the municipalities cannot afford to pay SGNG's demand charges. MGAG styles the data request as "putting words" in MGAG's mouth without any reference to specific testimony and as a "fishing expedition and nothing more." And so it is. The financial condition of a pipeline's downstream customers is pure and simple irrel

evant.

The motion to compel a response to data request 36 is denied.

¶ 63,026

Cor

led

Phase

Company

I. Introduction

The Federal Energy Regulatory Commission, as part of its continuing efforts to reshape the natural gas industry along more efficient and competitive lines, issued a policy statement on May 30, 1989 regarding the design of rates for interstate natural gas pipeline services Interstate Natural Gas Pipeline Rate Design, 47 FERC 61,295 Order on Rehearing 48 FERC [61,122 (1989). The administrative law judges and parties to a number of pending rate proceedings were instructed to develop records which delve into and resolve certain enumerated rate design issues consistent with the directions of the policy statement. Phase II of this proceeding, the subject of this Initial Decision, was devoted exclusively to the policy statement issues.

The anticipated complete abandonment of Paiute Pipeline Company's sales service has resulted in an exploration of the rate design issues facing an exclusively open-access transportation pipeline. With the exception of rates for Paiute's interruptible transportation service, for which flexible value of service pricing is adopted, this Initial Decision retains the modified fixed variable (MFV) rate design of the Phase I settlement.

A. Background

Paiute Pipeline Company (Paiute) is an interstate natural gas pipeline providing services from the Idaho-Nevada border southwest to the Lake Tahoe area in northern Nevada. On May 17, 1988 the Commission approved an offer of settlement creating Paiute as a wholly owned subsidiary of its parent, Southwest Gas Corporation (Southwest). It authorized Paiute to succeed to the Natural Gas Act jurisdictional sales service that Southwest had been providing to Sierra Pacific Corporation (Sierra) and CP National Corporation (CP National). Southwest Gas Corporation, 43 FERC ¶ 61,257 reh'g denied 44 FERC 61,165 (1988). In

Pacific Power addition, Paiute was authorized to begin mak

ing new sales for resale to its parent's local distribution companies, Southwest-Northern Nevada and Southwest-Northern California. The sales tariff employed by Paiute was the one previously in use by Southwest.

As a condition of the progenitor settlement, Paiute was required to apply for a blanket open-access transportation certificate under 18 CFR. $284.221 and propose new sales and transportation tariffs. In November 1988 the Commission granted Paiute its blanket certifi

cate, accepted its proposed tariff sheets subject to refund, conditions, and suspension periods, and ordered a hearing concerning the lawfulness of the proposed rates. Paiute Pipeline Company, 44 FERC ¶ 61,326 (1988). Paiute's LDC customers, the Northern Nevada Industrial Gas Users (Industrial Users or NNIGU), the Nevada Public Service Commission, and the Nevada Attorney General have intervened in this proceeding.

By the time the Commission issued its rate design policy statement, prehearing conferences had been held and substantial progress had been made in settlement negotiations in the underlying rate case. Accordingly, Presiding Administrative Law Judge Benkin divided this proceeding into two phases. (Tr. 138) Phase I was designated for resolution of the cost-of-service issues and rate issues without regard to the policy statement. A contested offer of settlement of the Phase I issues was certified to the Commission on March 20, 1990.

On September 12, 1990 the Commission modified and accepted the offer of settlement in Phase I. Paiute Pipeline Co., 52 FERC ¶ 61,311 (1990). The settlement seeks to resolve cost of service, anticipated throughput volumes, refund calculations, depreciation rate issues, and associated tariff changes. An MFV rate design is embodied in the Phase I settlement although the settlement itself disclaims reliance on this rate design in Phase II of this proceeding.

The Commission-modified settlement, if finally approved and accepted by the Commission and Paiute, will radically restructure the pipeline's operations. Paiute will discontinue sales of natural gas entirely and begin providing only transportation and storage services. The rates for transportation and storage contained in the settlement are to be effective until a final decision in this Phase, at which time the Phase II rates calculated in accordance with rate design decisions to be enunciated in Phase II are to apply prospectively.

Hearings were held in Phase II of this case in March 1990 before Presiding Administrative Law Judge Isaac D. Benkin. Upon Judge Benkin's retirement, this case was reassigned to the undersigned for decision.

B. Evolution of rate design methods

The rate design process is intended to determine specific rates for classes of customers and types of services that will recover a pipeline's cost of service in a manner consistent with the

Natural Gas Act's requirement that rates be just and reasonable and not unduly discriminatory.

After passage of the Natural Gas Act in 1938, the newly created Federal Power Commission initially adopted a policy of allocating costs in accordance with a straight fixed-variable (F-V) methodology, employing the demand and commodity charge concepts used in other utility regulatory contexts. The FPC explained that pursuant to the fixed-variable methodology:

[C]osts are divided essentially into two groups, fixed and variable. Fixed costs are largely joint costs which do not vary with volumes of sales. The total amount of such costs is largely proportional to the maximum demand on the system or system capacity. Accordingly, these costs have been allocated basically in proportion to each customer's responsibility for the peak day demand. Variable costs are largely those that vary proportionally to the output or volume of sale. Accordingly these costs have been allocated in proportion to volume of gas purchased by each customer.

Canadian River Gas Co., 3 FPC 32 (1942) aff'd sub nom Colorado Interstate Gas Co., 324 US 581 (1945).

The FPC reconsidered the propriety of recovering all of a pipeline's fixed costs based on peak day demand in 1952, reclassifying half of the fixed costs from demand to commodity in Atlantic Seaboard Corp., 11 FPC 43 (1952) (Seaboard). The FPC stated that it was unable

to accept the premise that merely because certain costs do not vary with use they automatically become in toto demand or capacity costs. A pipeline would not normally be built to supply peak service, that is to say, service on the peak days only.

11 FPC at 54.

In ANR Pipeline Co., 37 FERC ¶61,263 (1986), the Federal Energy Regulatory Commission noted that the FPC's decision in Seaboard was:

a result of its recognition that a pipeline serves the dual purpose of providing peak capacity service and annual service. Since

=

1 Load Factor Average Daily Demand of a customer Peak Day Demand of that customer. If the peak day is that of the customer, the load factor is termed "non-coincident." If the peak day is that of the pipeline, the load factor is termed "coincident."

2 If all or most of a pipeline's fixed costs are in the demand charge (as in F-V rate design), a higher load factor customer spreads out its burden for these costs over the large volumes that it takes throughout the year at the less expensive commodity charge rate (the commodity charge is low, or "unburdened"

neither peak usage nor annual service was found to be the predominant function of the system, half of the fixed costs were classified to demand with the other half being classified to the commodity component.

37 FERC at p. 61,733.

In addition to reflecting notions of the equitable method of distributing fixed cost responsibility among peak and off-peak users, the demand/commodity allocation decision has been used to send 'price signals' aimed at achieving policy-oriented goals.

The result of a reclassification of fixed costs from the demand charge to the commodity charge, as was done in Seaboard, is a shift in the relative burden of revenue responsibility among customers with differing load factors.1 Since the costs to be recovered in the demand charge are assessed in proportion to each customer's share of entitlements to peak capacity, there is an inverse relationship between a customer's load factor and its unit cost of gas that is more pronounced when more costs are classified to demand. Accordingly, shifting costs from the commodity charge to the demand charge increases firm customers' incentive to improve their load factors with additional offpeak service or reduced peak demand. It also results in a shift in allocation of costs from high load factor customers to low load factor customers. Shifting costs from the demand charge to the commodity charge has the opposite effect, making off-peak service more costly and unit-cost/load factor considerations less important.2

Faced with a severe gas supply shortage in the 1970's, the FPC relied on the price signal aspect of fixed cost allocation to encourage conservation. In United Gas Pipe Line Co., 50 FPC 1348, 1362 (1973) the Commission classified 75 percent of United's fixed costs to the commodity charge as a disincentive to throughput, noting that "the national problem of gas shortage bears on the allocation issue and circumstances require us to adopt policies which will promote the utilization of gas that will conserve available supplies to the greatest extent possible."

The gas supply shortage, however, was not long lived. It had been artificially created by

because the fixed costs are recovered in the demand charges). The less fortunate low load factor customer who does not purchase or ship consistent large volumes at the unburdened commodity charge pays a higher unit cost per volume when its demand charges are considered. (For example, a customer who uses half of the peak day capacity pays half of all of the pipeline's fixed costs even if its total annual usage of the pipeline is only one tenth of the pipeline's business.)

the difficulties the FPC encountered in trying to regulate effectively independent (nonpipeline owned) producer prices. See Pierce, Reconstituting the Natural Gas Industry from Wellhead to Burnertip, 9 Energy Law Journal 1, 8-11 (1988). As a result, the shortage was quickly transformed into a "bubble" of excess supplies by the Natural Gas Policy Act of 1978 and earlier corrective initiatives taken by the FPC in the 1970's (tripling of area rate ceilings). See Id. at 11-15,

With the reversal of the supply situation, the premises of the United methodology, that peak use in times of curtailment is of diminished relative importance as compared to annual usage and that rates should encourage conservation, were no longer valid. The Commission responded by reclassifying fixed costs from the commodity charge to the demand charge to encourage increased throughput. Natural Gas Pipeline Co. of America, 25 FERC 61,176 (1983) (Natural).

In Natural, the Commission noted an absence of the factors responsible for the United methodology and that gas supply was adequate to meet demand. Id. at p. 61,481. The Commission substantially affirmed the Initial Decision of Judge Head who found a need for "a reduction in the commodity charge

under current circumstances to sell the overabundance of gas supply to prevent take-orpay penalties and to stem the loss of industrial load, if possible." 23 FERC ¶ 63,032, at p. 65,068. Return to the Seaboard methodology was considered but ultimately rejected as inadequate to meet the needs of the supply situation:

The case is not nearly as strong for departing from the Seaboard method as it is for departing from United. However, the need to remove demand charges from the commodity component to make the marketing of gas more viable in the current situation of gas overabundance and low price competing alternative fuels, is sufficient to warrant the adoption of an alternate method.

23 FERC at p. 65,069.

Although unburdening of the commodity charge further than Seaboard was a practical requirement, the Seaboard principle that annual service serves an important function that should be reflected in rates retained its validity as a ratemaking principle. Accordingly, Judge Head and the Commission declined to return to the straight fixed-variable

3 Imputing a load factor other than 100 percent results in an imputed contract demand equal to estimated annual throughput divided by the result of multiplying 365 by the load factor expressed as a multiplicand (e.g., for a 200% load factor the equation

methodology. Rather, the Modified Fixed-Variable (MFV) methodology was adopted.

For purposes of allocating demand costs between classes of customers and among customers, we conclude that equal weight should be given to a customer's highest Daily Quantity Entitlement (i.e., the daily contract quantity) and to a customer's Monthly Quantity Entitlement which, when aggregated, equal the Annual Entitlement of that customer. This determination is consistent with the Initial Decision's conclusion that an annual measure should be used for allocating demand costs and carries that measure through to the setting of rates for customers. 25 FERC 61,176, at pp. 61,483-84.

As the name implies, MFV is similar to the original fixed variable methodology with some modifications. Instead of classifying all fixed costs of service for recovery in the peak day demand charge as in straight F-V, MFV places the pipeline at risk for an amount equal to its return on equity and related taxes by classifying those costs to the volumetric commodity charge. MFV then divides the remaining fixed costs equally between a peak demand charge (D-1) and an annual throughput related demand charge (D-2).

D-1 is assessed as the demand charge had been in the straight fixed-variable method - in proportion to each firm customer's share of peak capacity. D-2, on the other hand, is a unit charge assessed in proportion to each firm customer's share of annual capacity.

Prevailing Commission policy regarding allocation of fixed costs to the interruptible service uses a "100-percent imputed load factor" to determine the interruptible rate. In a nutshell, "imputing" a load factor to the interruptible rate means that the entire interruptible service is treated as a single firm customer for the purpose of demand cost allocation. It creates the fiction that the interruptible service has a peak day contract demand that can be included in the determination of D-1 charges. The imputed contract demand determines what share of the fixed costs classified to D-1 are expected to be recovered by the interruptible service, conversely, it also determines the share of fixed D-1 costs that firm customers will be billed for in D-1 charges. Imputing a 100-percent load factor results in an imputed contract demand that is equal to the estimated average day (estimated annual interruptible throughput 365).3

is: estimated annual interruptible throughput + [2 365]). The higher the load factor, the lower the imputed contract demand and hence, the lower the D-1 fixed cost responsibility ascribed to the interruptible service.