been sold to the pipeline in contemplation of its resale in interstate commerce. On the other hand, the gas to be sold by producers directly to high priority non-resale customers, will not become part of a larger volume of gas that is subject to resale. While this direct sale gas may be temporarily commingled in transit with resale gas, it is commingled solely for the purpose of transportation and never becomes subject to resale. It therefore appears to us that the direct sales contemplated by the instant policy statement are non-jurisdictional and beyond our regulatory control. [Footnote omitted.]

Consistent with the Commission's above circumscription of Lo Vaca, the commingling doctrine is inapplicable here and jurisdiction over Texas Crude does not extend beyond that portion of the Blue Buck Point production that is resold by GE to Natural.

Economic Impact of In-Place Sales

The economic effect test, referred to earlier, was used in analogizing in-place sales to conventional wellhead sales for purposes of determining jurisdiction. The economic impact, now to be discussed, relates to the resultant influences of inplace sales upon the scheme of natural gas regulation.

Under the Natural Gas Act, in-place sales of proven and substantially developed reserves have the potential for a two-fold economic impact upon the regulatory processes of this Commission. First, the acquisition of gas in this manner by an interstate pipeline could result in rate charges to its jurisdictional customers in excess of what they would have paid under just and reasonable standards applicable to conventional wellhead sales." Second, successful disposition of gas on an unregulated basis might tend to lever producer asking prices, above regulated ceilings, thereby eliminating interstate pipelines as potential buyers of such reserves; particularly where the Commission sanctions the use of jurisdictional facilities to deliver non-jurisdictional volumes. Under the first possibility we look toward what the purchaser's total costs are whereas under the second possibility we must concern ourselves with the full consideration received by the seller.

Under the first possibility, an interstate pipeline purchasing reserves in-place usually pays a lump sum for the interests conveyed. The pipeline assumes the role of a producer; incurring all costs attendant to maintaining the wells, maximizing the amount of gas to be recovered and bearing all production risks. These and other factors, particularly the volumes estimated to be recovered, make it difficult to quantify the total cost to the buyer in the initial stages of production. Such a calculation can be accurately made only after the field is fully depleted. Nevertheless, where the Commission found that a particular in-place sale was subject to its jurisdiction, it attempted to conventionalize such

a sale at the time of purchase so as to limit the cost to the pipeline purchaser to an amount equivalent to what would have been paid under Commission ceiling prices for a conventional per Mcf purchase. See e.g., Rayne Field, supra.

The facts of the instant in-place transaction, however, do not warrant such an attempt at conventionalization. The interstate pipeline, Natural, is and will be purchasing a minimum of ten percent of the Blue Buck Point production at Commission authorized ceilings under GE's certificate in Docket No. CI77-449. Thus, Natural's customers are fully insulated against the risk of being charged rates that are not "just and reasonable." Since the volumes over which Commission jurisdiction extends are a relatively small portion of the total Blue Buck Point production, conventionalizing that part of the transaction (assuming it were possible) to ensure that GE, the intermediary purchaser, does not pay for that percentage a consideration in excess of a just and reasonable rate, would be tantamount to the tail wagging the dog.

As a consequence of the above, both GE and Natural maintain that there is no reason for jurisdiction to be asserted over Texas Crude for that portion of the transaction since it would be a meaningless act on the part of the Commission. Now it is recognized that in these circumstances the assertion of jurisdiction is a purely ministerial task. And critics of the regulatory process might well contend that such acts of otiosity represent the apogee of superfluous bureaucratic regulation. Nevertheless, there is nothing in the Natural Gas Act or in its legislative history that grants discretion to the Commission in the exercise of its jurisdictional mandate. To the contrary, although the Commission may have the power to waive certain filing requirements set forth in its Rules and Regulations," the statutory language of the Natural Gas Act makes it incumbent upon the Commission to require certificates of public convenience and necessity for all jurisdictional sales:

shall engage in

No natural gas company the transportation or sale of natural gas, subject to the jurisdiction of the Commission unless there is in force with respect to such natural gas company a certificate of public convenience and necessity issued by the Commission authorizing such act or operations. Section 7(c); 15 U.S.C. 717f(c).

The second possible economic impact, that of an upward leverage upon the market price for uncommitted reserves resulting from in-place sales of gas at prices in excess of Commission approved ceilings, has no direct bearing upon an initial determination of jurisdiction. Rather, once jurisdiction is found to exist, be it a sale for resale under the guise of a leasehold acquisition or the use of interstate facilities to transport gas purchased in

place by a direct user, then the likelihood of interstate pipelines being eliminated as viable competitors for uncommitted reserves becomes relevant in determining whether the proposed sale or transportation should be certificated as being "required by the present or future public convenience and necessity."" Consequently, it is appropriate to defer a discussion of this potential economic impact for subsequent sections of this Initial Decision. The evidence relative to whether Texas Crude received a consideration for the Blue Buck Point sale in excess of what it might have received under a conventional jurisdictional sale or an intrastate sale will be evaluated in the next part of this Initial Decision. Thereafter, the putative upward leverage of the market price for uncommitted reserves caused by in-place sales in general, and the Blue Buck Point sale in particular, if applicable, will be considered in the discussion of the policy implications of authorizing long-term transportation of industry-owned gas, particularly in light of the recent passage of the Natural Gas Policy Act.

PIPELINE TRANSPORTATION

CERTIFICATES

In its order of December 30, 1977, the Commission granted rehearing in the three dockets consolidated in this proceeding for the purpose of determining "whether the transportation arrangements should be authorized and under what conditions." Accordingly, at the prehearing conference, the Presiding Judge stated that the pipeline applicants were required to present "evidentiary support for some of the crucial elements of the transactions" (Tr. 17). Such elements were deemed to include:

(a) Whether sufficient capacity exists on the respective systems.

(b) Whether dedication of the specified capacity will have a detrimental effect on the remaining

customers.

(c) Whether the proposed transportation rates are justified.

(d) Whether the percentage of volumes to be retained by three of the pipeline transporters for company-use and unaccounted for is justified.

This section of the Initial Decision will evaluate the evidence presented by the pipeline applicants to determine whether each, standing alone, should receive certificate authorization. The preliminary decision regarding each applicant will then be reevaluated upon an analysis of: (1) the evidence relative to GE's operations and (2) the total consideration received by Texas Crude, in order to determine whether approval of the entire GE transportation proposal "is or will be required by the present or future public convenience and necessity." Section 7(e); 15 U.S.C. 717f(e). To what extent the conclusions thus derived are to be altered by virtue

of policy findings will be the subject of a subsequent part of this Initial Decision.

Natural Gas Pipeline Company's Transportation

Witness Sumonka, Director of Rates and Certificates for Natural, testified as to the terms and conditions of Natural's transportation agreement in Docket No. CP77-71. Natural proposes to transport up to 6,000 Mcf per day of Blue Buck Point gas to be delivered to Natural at the Sabine Delivery Point in Cameron Parish, Louisiana. Natural is to redeliver thermally equivalent volumes of gas to Texas Gas for GE's account at the Erath Redelivery Point, Vermilion Parish, Louisiana. In return for such service, Natural proposes to receive from GE a payment equal to the greater of 4.0 cents per Mcf for all gas transported during any month or a monthly charge of $1,500. Natural also has the right to purchase from GE approximately ten percent of the gas delivered to Natural (Tr. 152-153).

With regard to pipeline capacity and the impact of transporting GE's gas upon existing pipeline customers, Witness Sumonka testified that the Natural-GE Agreement will have no detrimental effect upon Natural's present customers throughout the ten-year contract period (Tr. 151-153). The Sabine Delivery Point is downstream of the Erath Redelivery Point, therefore, the GE gas is "redelivered" simultaneous with its "delivery." The "displacement" nature of the service insures that there is no reduction in the pipeline capacity available to Natural's present customers.

The witness further testified that the amount of GE gas being received by Natural at the Erath Redelivery Point is so small in comparison to the amount of other gas being taken by Natural at that point, that Natural cannot envision any problem with this type of displacement arrangement. Nor would transportation of the GE gas preclude Natural from making emergency purchases in the future because such purchases are not made in the part of Natural's system where the GE gas is delivered (Tr. 251).

Witness Sumonka also testified regarding the basis for the proposed transportation rate. He indicated that this rate reflects in part, a rate of 2.5 cents per 100 miles multiplied by the 114-mile distance between delivery and redelivery points. This rate is the average system-wide cost of haul based upon cost data filed by Natural in Docket No. RP76-106, as adjusted pursuant to Commission orders, and to eliminate certain nonrelated costs (Tr. 153-154, 287). The rate also takes into account the effect of inflation over the projected ten-year period (Tr. 154, 260-261). Although the rate charged to GE (4.0 cents) was not derived precisely from a formula previously approved by the Commission, at the time the rate was assessed it was within 0.2 cents of the rate derived under an approved formula (Tr. 288-290).

Witness Sumonka further testified that the minimum monthly charge of $1,500 was negotiated to reimburse Natural for administrative overhead and other costs incurred whether or not any gas was transported for GE (Tr. 154, 264). The witness stated that this charge was appropriate in that GE was using available capacity in Natural's system and derived some benefit from its use. Revenues received by Natural from the transportation service are to be credited against the pipeline's cost of service (Tr. 155). In conclusion, the witness stated that the ten percent option obtained as part of the contract was consistent with an evolving policy of Natural in circumstances where transportation services are provided for off-system customers (Tr. 156, 229, 235).

and

Columbia Gas Transmission Corporation Columbia Gulf Transmission Company's Transportations

Columbia Gas and Columbia Gulf (the Columbia Companies) presented three witnesses regarding their transportation arrangement with GE in Docket No. CP77-118. Witness Robert M. Bennett, Director of Planning for Columbia Gas, testified that the Columbia Companies have agreed to transport on a best efforts basis up to 1,500 Mcf per day, delivered into existing facilities of Columbia Gulf located at Erath, Vermilion Parish, Louisiana and redelivered to Columbia Gas at an existing point in Boyd County, Kentucky. Columbia Gas will transport and deliver the gas to Baltimore Gas & Electric Company (BG&E) which, in turn, will redeliver the gas to GE's plant in Columbia, Maryland (Tr. 138-139).

In regard to system capacity, Witness Bennett testified that although ten years was a considerable length of time, so long as deliveries to BG&E for GE's account were within BG&E's contractual "Total Daily Entitlement" from Columbia Gas, it would be reasonable to assume that capacity will be available for a ten-year period; particularly as the volume of gas transported for GE is extremely small in comparison to the through-put capabilities of the Columbia Companies' system (Tr. 138-139, 191). Columbia Gas anticipates additional system capacity will become available in the near future when deliveries of revaporized LNG from Columbia LNG Corporation begin (Tr. 138–139). If, at some time in the future, GE's gas cannot be transported on a best efforts basis because of lack of capacity under the transportation agreement, the Columbia Companies may request GE to make contributions for construction of new facilities in proportion to the volumes being transported for GE (Tr. 139).

If a situation arises where there is insufficient capacity to serve all customers, then, with respect to an emergency purchase by either an affiliated or non-affiliated distribution company, such a customer would not have priority for transportation capacity over GE; "We [the Columbia Companies] take them on the basis of which one was negotiated

first" (Tr. 204). In a capacity shortage situation, Priority 1 requirements would cause the interruption of any industrial transportation service, but interruption would not occur to serve the needs of Priority 2 process users (Tr. 205).

Witness E. B. Motley, Director of Rates for Columbia Gas, testified regarding the rate charged GE by that company. The witness stated the transportation charge reflects the company's average system-wide unit storage and transmission costs, exclusive of company-use and unaccountedfor gas as reported in the company's rate filings with the Commission. This charge of 20.56 cents per Mcf is subject to adjustment whenever a new rate filing is made (Tr. 142). Similarly, the percentage of gas retained for company-use and unaccounted-for volumes (4.0 percent), is based upon the volumes reflected in the rate filings. The methodology employed by the company in computing the transportation rate and percentage of gas retained has been approved by the Commission in several recent orders (Tr. 142).

Witness Larry A. Ledsome, Manager of Rates for Columbia Gulf, testified regarding the basis for the 27.69 cents per Mcf transportation rate charged, and the 3.3 percent of gas retained for company-use and unaccounted-for volumes (Tr. 145–146). He indicated that the rate charged is based upon Columbia Gulf's cost of transportation through onshore system facilities, as reflected in the level of costs included in a settlement approved by the Commission on March 16, 1978, in Docket Nos. RP76-94 and RP76–138. According to the witness, Columbia Gulf's transportation charges applicable to GE were developed in the same manner as similar transportation charges which received prior Commission approval (Tr. 146). The witness also testified the foregoing comments were equally applicable to the derivation of the 3.3 percent. Texas Gas Transmission Company's Transportation

Witness Ray S. Smith, Assistant to the Vice President of Sales, testified regarding the interruptible transportation service to be provided GE in Docket No. CP77-125. Texas Gas proposes to provide up to 2,000 Mcf per day to Louisville Gas & Electric Company for delivery to GE's plant in Louisville, Kentucky, up to 250 Mcf per day to Indiana Gas for delivery to GE's plant in Bloomington, Indiana, and up to 1,500 Mcf per day to Columbia Gulf who will transport such gas to an existing delivery point in Boyd County, Kentucky for transfer to Columbia Gas for delivery to BG&E, and ultimately to GE's plant in Columbia, Maryland.

On the issue of pipeline capacity, Witness Smith testified that Texas Gas expects to be able to render transportation service to GE for the ten-year contract period, and to have the delivery capability to perform all existing services to the extent of the available supply (Tr. 163). Moreover, the proposed

GE transportation is subject to interruption should this capacity be required to transport general system supply (Tr. 163). Although the pipeline has purchased some emergency gas for its distribution company customers as well as for general system supply, the witness testified that Texas Gas has never encountered any capacity problems with regard to the transportation of gas for distribution and industrial users; any lack of capacity to perform transportation services is "purely a hypothetical situation" (Tr. 306, 314-315). If a capacity problem should develop, Texas Gas would not give preference to distribution companies but would curtail all transportation services for distribution and industrial companies on a pro-rata basis. Transportation of gas purchases for general system supply, be they purchased by the pipeline as emergency supplies or otherwise, would take precedent over all other transportation services (Tr. 313-317).

With regard to the transportation charges to GE, Texas Gas is charging 27.63 cents per Mcf delivered to Indiana Gas Company and 30.36 cents per Mcf delivered to Louisville Gas and Electric Company. These rates are based upon cost data presented in Texas Gas' most recent rate case. Costs are fully allocated to this transportation service and are the same as the costs which are assigned to the company's sales for resale in each of Texas Gas' rate zones; costs are based upon the cost of service less production and compressor fuel costs (Tr. 346). The rate methodology employed by Texas Gas is generally the same as that used by Natural (Tr. 347). The transportation agreement with GE contains a provision for a minimum bill based upon 2.5 percent of the total contract demand of 2,250 Mcf per day which, the witness stated, is the point at which Texas Gas believed it could "come out whole" (Tr. 349).

Witness Smith also testified that Texas Gas retains as makeup for compressor fuel and line loss 9.1 percent of volumes delivered to Indiana Gas and 8.6 percent of volumes delivered to Louisville Gas and Electric for GE's account" (Tr. 163). These percentages are calculated on an incremental basis for pipeline through-put to and within the rate zones in which deliveries by Texas Gas are made for GE's account (Tr. 163, 347).

Conclusion as to Pipelines' Presentations

Upon review of all of the evidence submitted by the pipeline applicants (none of which was butted), the arguments of all parties in the briefs, and in consideration of the fact that the transportation services proposed will be on an interruptible asis (to be more fully discussed in the next ction), it is held that each of the pipeline appliants "is able and willing to do the acts and to erform the service proposed" (Section 7(e) of the ct).

Proposed Capacity Condition

Northern Illinois Gas Company (NI-Gas), a

distribution company and intervenor herein presently served by Natural, proposes that if, in reviewing the record in this proceeding the Commission decides to issue a policy statement approving longterm transportation of industry-owned gas, then the Commission should "include a condition upon any transportation certificate to the effect that industry may not preempt pipeline capacity that would otherwise be available to pipelines and distributors to transport volumes of additional gas acquired for the purpose of offsetting curtailments below contract entitlement. This condition should include gas acquired by pipelines or distributors under both Section 7 of the Natural Gas Act and under Sections 2.68 and 157.22 of the Commission's Regulations." (Initial brief at 19)

The Commission Staff initially expressed the belief that pipeline capacity was not in issue in this proceeding since the transportation service proposed will be on an interruptible basis (initial brief at 40). However, in its reply brief, the Staff supported a policy imposing a capacity condition upon any long-term transportation on the theory that such a policy would "insure that future transportation arrangements will not adversely affect the consumer" (at 18). Texas Gas, Natural, The Process Gas Consumers Group and Libbey-OwensFord Company oppose the inclusion of a capacity condition in any certificate authorization on the ground that it is unnecessary and addresses nonexisting capacity problems. GE, on the other hand, has indicated a willingness "to accept a condition to a ten-year transportation certificate which would accord transportation priority to any gas being transported on behalf of distribution company customers within their certificated contract entitlements over any gas being transported on behalf of industrial customers. GE would be willing to accept such a condition as long as GE was treated on the same basis as other industrials, i.e., limited capacity to transport industrial gas would be prorated among all industrial users (Tr. 539-542)." (Initial brief at 49)

In support of the imposition of its proposed condition, NI-Gas argues that it is necessary to prevent the situation arising where a pipeline has gas available to make up for curtailments (e.g., short-term emergency purchases), but is unable to transport such volumes because the necessary capacity was previously preempted by certification of a long-term transportation of industry-owned gas. The same situation could occur where the distributor customer has volumes available to replace pipeline-curtailed volumes but is unable to have such gas transported by his pipeline supplier due to a similar preemption of capacity. Moreover, according to NI-Gas, "the granting of long-term certificates of transportation to industrial users will create a disincentive to pipelines and distributors, whose total capacity would still be used, to search for natural gas to bring to their customers to make up

for curtailments" (Initial brief at 22). Finally, NIGas maintains that "the record in this case establishes a clear need for the kind of condition being suggested ***." in that "both Columbia Gas and Natural testified that portions of their system were already operating at system capacity" (Id. at 23). We turn first to this latter contention.

At the outset, it is noted that NI-Gas is a customer of Natural and is not served by any of the other pipeline applicants. Thus, should capacity limitations result on Natural's system by virtue of any authorizations granted here, NI-Gas may be directly affected. In attempting to establish that Natural's proposed transportation will in fact exacerbate existing capacity limitations from the standpoint of Natural's ability to purchase and transport long-term or emergency volumes for system-wide use, NI-Gas refers to a portion of the testimony of Natural's Witness Sumonka. Specifically, it is that testimony describing Natural's Gulf Coast system, which extends from the Texas Gulf to the Chicago area and operates at capacity most of the year. Witness Sumonka agreed that if emergency gas were available for purchase by the pipeline, on what counsel for NI-Gas referred to as the Gulf Coast Line, "Natural would have a problem hauling it" (Tr. 252). NI-Gas claims that this statement indicates an existing capacity limitation on Natural's system which will be aggravated by the movement of GE volumes through that system (Initial brief at 24). However, the evidence of record does not support the conclusion drawn by NI-Gas.18

Witness Sumonka testified that Natural generally purchases emergency gas on its Amarillo system and although "a very minimal amount" of emergency volumes were purchased in the past on the Gulf Coast system, none was bought on the Louisiana Lateral which is the portion of that system utilized in the displacement arrangement for transporting the GE volumes (Tr. 250-251):

This gas that we are talking about here [GE volumes] has nothing to do with our Amarillo system but it is on our Gulf Coast system. Not even that, it is on the adjunct connection to the Gulf Coast system. It is done by displacement. It actually helps us move gas, if anything. It is neutral in its effect in the system.

As for the Columbia Gas system, NI-Gas points to the testimony of Columbia Gas' Witness Bennett where he indicated that the part of the Columbia Gas system which serves Baltimore Gas (which in turn serves GE) at times "does operate at full capacity" (Tr. 206). But here again that statement is meaningless unless viewed within the context of Witness Bennett's further statement that if the old Atlantic Seaboard system utilized for deliveries to Baltimore Gas were operating at full capacity to meet the total entitlements of Columbia Gas' customers, "we would not deliver gas for G.E. in excess of the total daily entitlements of Baltimore

Gas and Electric" (Tr. 206). Moreover, continued Witness Bennett (Tr. 206-207):

*** Baltimore has indicated that they in fact would not serve gas that would require a take from Columbia Transmission greater than their total entitlement.

Texas Gas suggests that since no evidence was adduced on the record to indicate that it would encounter capacity problems on its system during the term of the GE transportation service, the proposed NI-Gas condition is unnecessary (Reply brief at 1). Texas Gas notes that NI-Gas advanced the identical proposal in the context of a rulemaking proceeding initiated by the Commission to review policies embodied in Order Nos. 533 and 533-A (Commission Order No. 2, issued February 1, 1978, in Docket No. RM75-25, FERC Statutes and Regulations ¶ 30,005). There, the Commission rejected the NI-Gas proposed condition for the following reasons (mimeo at 17):

NI-Gas did not cite a single instance where the pipeline capacity on any interstate system has been preempted. In addition, one of the necessary findings in the approval of the 533 application is that there is available pipeline capacity. A concerned distributor could therefore address this issue in a specific proceeding when the proposed transportation is under consideration; however, since this problem does not appear to have actually happened, there is no basis at the present time for a general pronouncement on this point.

The above observation was made within the framework of Order No. 533 authorizations for a term of only two years. It was therefore reasonable for the Commission to presume that if at the time of certification of an Order No. 533 proposal no evidence was adduced as to capacity limitations, that situation should prevail on that pipeline system for the next two years. Here, however, we are confronted with a ten-year term and are therefore required to explore, under the present or future public convenience and necessity standards of Section 7 of the Act, the reasonableness of attaching a capacity condition to the grant of any transportation certificates.

Since all of GE's volumes will be transported on an interruptible basis, at first blush it would appear that the GE transportation service will be subservient to the pipeline applicants' obligations to meet existing customers' contract entitlements. Thus, during curtailment periods due to a gas supply shortage, the pipeline could attempt to satisfy the existing customers' contract entitlements either: (1) through its purchase of emergency or long-term supplies of gas, or (2) through the transportation of emergency volumes purchased and owned by the distributors. This presumably would be accomplished through the use of existing unused capacity or, if none was available, through the interruption of the GE transportation service.