JOHN R. BROWN, Senior Circuit Judge.

A Gathering of Shippers

Various petitioners 1 , banded together as the “Indicated Shippers” in this case, seek review of the Federal Energy Regulatory Commission (FERC) decisions in Northern Natural Gas Co., 37 FERC 11 61,272 (1986) and 41 FERC 1161,158 (1987), in which FERC approved a settlement establishing the rates and terms under which Northern provides transportation services for competing natural gas sellers under FERC’s Open Access Order No. 436. 2

*1025 In a general way, the Indicated Shippers contend that FERC, through Northern’s rates as approved by FERC, has allowed Northern to maintain an undue competitive advantage for its own natural gas, primarily by (i) not offering adequate price distinctions between the types of transportation services offered, (ii) by improperly allocating costs to transportation rates, and (iii) not basing those rates on projected volumes as required.

On review of FERC’s decision approving the settlement, we affirm.

Open Access and Order No. 436

Order No. 436 has restructured the role of interstate gas pipelines by opening the use of pipelines to third party gas sellers. Prior to this, pipeline owners operated primarily as gas merchants, buying gas at the well head and shipping it over their own pipelines for sale to distributors for resale in the market or directly to commercial users. As restructured under open access, pipelines are to serve as transporters of natural gas not only for themselves but for others, even those who might be in competition with the pipeline in its role of gas merchant. As seen in the instant appeal, one result of the restructuring is that competition has shifted to the rate-making process. 3

Northern and the Transportation of Natural Gas

As all know, FERC is the government agency that regulates the operation of privately-owned pipeline systems, the rates they charge, and under Order No. 436, access to such systems by competitors of the pipeline operator.

Northern operates an integrated, interstate pipeline system that runs from offshore producing fields in the Gulf and onshore producing fields in Texas, New Mexico, Oklahoma and Kansas (the Field Area) to its primary market area in the upper Mid-west, comprising Nebraska, Iowa, South Dakota, Minnesota, Wisconsin and Michigan (the Market Area). Natural gas flows North through Northern’s mainline from the Field Area to the Market Area. Smaller lines feed into the mainline from throughout the Field Area, which ends around Northern’s Kansas compressor station. In the Market Area, the mainline from the South branches into an inter-connecting grid. Significant amounts of natural gas enter the Market Area system from several sources and directions. 4 Thus the natural gas flows in many directions and from many diverse initial sources.

FERC Tries A New Approach

On October 9, 1985, FERC issued Order No. 436 establishing a new transportation scheme for the interstate movement of natural gas in pipelines. FERC did this by amending its regulations regarding self-implementing transportation under § 7(c) of the Natural Gas Act 5 and § 311 of the

*1026 Natural Gas Policy Act. 6

Under Order No. 436, the transportation of natural gas must be performed on a non-discriminatory basis. 7 Order No. 436 distinguishes between a pipeline’s transportation service and sales service. This allows a pipeline’s transportation customers the opportunity to purchase natural gas directly from producers in the field and then to transport that natural gas on a pipeline in competition with the pipeline’s own natural gas.

Order No. 436 undertakes to restructure the natural gas transportation system to foster more competition by allowing easier access to pipelines for non-owners of pipelines 8 on a nondiscriminatory basis. 9 In fixing transportation rates, the pipeline has to allocate, among other things, costs between sales gas 10 and transportation gas, 11 project the volumes of natural gas transported and design rates to recover costs for transportation of the projected volumes. Additionally, rates should reasonably reflect any material variance in the cost of providing service due to distance over which transportation is provided or due to seasonal differences during which transportation occurs.

Northern Files Proposed Rates with FERC

On September 26, 1985, Northern filed revised tariff sheets proposing changes in its sales and transportation rates which FERC subsequently set for a hearing. 12

Northern, on April 11, 1986, filed an offer of settlement 13 with FERC. In regard to both sales and transportation rates the settlement proposed costs of service, projected volumes, rate design and rate zones. Specific rates, terms and conditions were also proposed for Firm and Interrup-tible 14 transportation performed under Order No. 436. 15 FERC, by order issued on December 22, 1986, approved the Northern Settlement with certain modifications. 16

Indicated Shippers filed a petition for rehearing on January 21, 1987, challenging, inter alia, FERC’s approval Northern’s transportation rates, including the 100% Load Factor rate, Northern’s inclusion of storage and third party transportation costs, the use of postage stamp rates in the Market Area, and FERC's refusal to require a breakdown of projected units of service and peak and off-peak rates.

In the Order Granting in Part and Denying in Part Rehearing and Granting Clarifi *1027 cation issued on November 9, 1987, FERC affirmed its earlier decision on almost all issues, granting rehearing only on a point raised by Northern regarding its D-l Demand Rate. FERC, thus, allowed the Settlement to stand.

The Settlement: Transportation and Sales Rates

FERC approved, with modifications not relevant to this appeal, the cost of service for sales and transportation. FERC found that the 100% Load Factor rate for Inter-ruptible Transportation properly allocated fixed costs to the appropriate parties and reflected the difference in quality of service between Firm and Interruptible service. 17 Further, taking the position that no party objected to Northern’s projections of sales and transportation volumes, FERC found that although high, they were historically supported and met the requirements of Order No. 436. 18

The Settlement: Storage, Third Party Transportation, and Transmission Costs

In operating and maintaining its Market Area pipeline system, Northern incurs costs for (i) storage, (ii) third party transportation, and (iii) transmission. FERC has authorized Northern to charge these costs to its sales and transportation customers alike on a per-unit basis. Sales customers, Interruptible Transportation customers and Firm Transportation customers are, therefore, charged for all three services and at the same rate on a per-unit basis.

The Settlement: Postage Stamp Rates

FERC rejected objections to the use of uniform, “postage stamp” rates, as op-

posed to mileage based rates for Firm and Interruptible transportation in Northern’s Market Area. 19 FERC found that Order No. 436 does not require mileage based rates, but rather only requires that the rates reasonably reflect material variations in cost due to the distance of service. 20 Northern’s Market Area, (see n. 16, supra) FERC explained, was an interconnected multi-directional grid with multiple sources of natural gas so the actual flow of the natural gas to the ultimate user often bore no correlation to the transportation service performed. Consequently, the distance of the haul is irrelevant.

The Settlement: Seasonal and Off-Peak Pricing

Finally, in the Settlement authorized by FERC, no provisions were made for the adjustment of transportation rates due to seasonal or peak/off-peak variations in the pipeline’s capacity. FERC reasoned that such rates are not required by its regulations. 21 Rather, in the case of a party opposing rates that do not reflect seasonal differentiation, there must be an independent showing that such rates are appropriate. Such a showing is made if the party opposing the rates establishes that the costs of providing service varies materially during different periods. 22

The Appeal

Indicated Shippers on appeal urge that FERC erred because:

1. The Northern rates allowed by FERC are not supported by substantial evidence;

2. FERC, in fixing and approving the costs in Northern’s fee structure failed to (i) adequately include storage and other *1028 pipeline costs, (ii) disallow the use of the postage stamp rate, and (iii) require seasonal or off-peak rates; and

3. Northern failed to provide an adequate breakdown of projected units of service between Firm and Interruptible transportation.

Standard of Review

For FERC cases on appeal to the Eighth Circuit the standard of review is restricted in scope. This Court must accept findings of fact as conclusive if they are supported by substantial evidence. 23 Furthermore, the Court must defer to FERC when FERC makes determinations within its area of administrative expertise. 24 Thus, our focus is not on the end result but on the process employed by FERC. We do not sit in judgment of FERC policies but rather only on whether or not FERC has abided by its own process requirements and reached its decision by reasoned consideration. 25

Available Evidence and the Decision-Making Process

Finally, in our review, the requirement of substantial evidence can only be understood in the context of the evidence available to FERC. Order No. 436 has established a radically new transportation framework for natural gas. In one of the first opinions to explore the ramifications of Order No. 436, Judge Williams, writing for the D.C. Circuit, stated that

[t]he Order envisages a complete restructuring of the natural gas industry. It may well come to rank with the three great regulatory milestones of the industry: the passage of the Natural Gas Act, ... in 1938, the imposition of price controls on independent producers’ wellhead sales under Phillips Petroleum Co. v. Wisconsin, ... and adoption of the Natural Gas Policy Act ... in 1978.

Associated Gas Distributors v. FERC, 824 F.2d 981, 993 (D.C.Cir.1987) (citations omitted).

Consequently, what might take place, what might happen, what new problems might be encountered, what ultimate judgments on modification might be required or appropriate were all problems neither FERC nor the industry could perceive. The tentative, experimental nature of FERC’s guarded approach is highlighted by the fact that Northern’s rate structure was temporary in the sense that the rate was for three years. More evidence will develop obviously, and FERC will gain more experience in the operation of the new regulatory scheme as time goes on. It is quite permissible that this Northern order might constitute a laboratory for FERC in how open-access will or should be applied in the future. Necessarily we do not speak for eternity, much less what FERC— by whatever name then called — will or must hold on these issues.

Designer Rates

Essentially, this case is a controversy over how Northern has designed its transportation rates, and whether or not FERC’s acceptance of Northern’s settlement was appropriate.

Under § 4 of the Natural Gas Act, FERC is charged with ensuring that “all rates charged, made, demanded or received ... are just and reasonable.” 26 As stated in 18 C.F.R. § 284.7, there are three rate objectives for Part 284 transportation: (i) peak period rates should ration pipeline capacity 27 ; (ii) offpeak Firm service and Interruptible service rates should maximize pipeline throughput 28 ; and (iii) pipeline revenue requirements allocated between Firm and Interruptible service should be attained using projected units of service in peak and *1029 offpeak periods and at the maximum rate for each service. 29

In designing rates, any rate filed with FERC for Part 284 service must be a one part rate, referred to as the Volumetric Rate, 30 unless the service is Firm transportation for which a separate reservation charge is allowed. 31 The Volumetric Rate recovers costs allocated to the service to the extent that the projected units are actually purchased.

The reservation fee that is allowed for Firm transportation service is defined as recovering those fixed costs which “would be recovered by using the same ratemaking methodology used for determining the demand charge in the pipeline’s sales rates.” 32 All remaining fixed costs and all variable costs form the basis for the Volumetric Rate 33 — in the Sales Rate, all remaining fixed costs and all variable costs are recovered in the commodity charge. In addition, the Interruptible Transportation rate may not include any provision that has the effect of “guaranteeing revenue.” 34

Under the “modified fixed-variable” rate design method employed by Northern, 35 the fixed amd variable costs recovered in the Commodity charge for Sales service include return on equity and related income taxes. All other fixed costs, primarily costs associated with operating and maintaining the pipeline, comprise the Demand charge and hence the Reservation fee for Firm Transportation.

Firm Service, Interruptible Service and the 100% Load Factor Rate

Indicated Shippers contend that FERC erred in approving a rate equal to the 100% Load Factor rate 36 as the basis for the Interruptible Transportation rate because that allows Northern to charge essentially the same rate for both Interruptible and Firm service, for which there is no supporting substantial evidence. 37

As a corollary, Indicated Shippers further argue that FERC’s decision allows Northern to charge Interruptible Transportation Shippers the same rate as Firm Transportation Shippers, without affording Interruptible Transportation Shippers guaranteed access to the pipeline system.

What’s in a Name

The way we interpret the argument, the question is how to characterize the service that Northern offers. Should an inferior service — Interruptible Transportation— cost as much as a superior service — Firm Transportation — or has a customer who pays an annual reservation fee actually paid more for the service because that customer is always out the money paid to reserve space. 38

*1030 Order No. 436 requires any user to pay all of the costs associated with service. The quality of the service when it is available is essentially the same — transportation between given points — and the price for each type of service consequently, should recover all those costs entailed in constructing, operating and maintaining the pipeline. Indicated Shippers misinterpret FERC’s approach by, in essence, arguing that a “reservation” charge recovers those expenses necessary to offer a “reserved” service. 39 A pipeline does not entail two distinct sets of fixed costs, one associated with reserving capacity and one with utilizing capacity. Rather, it costs the pipeline the same, on a per-unit basis, to transport natural gas for either a Firm or Interrupti-ble customer.

As we are dealing with a question of FERC policy, this being an attack on FERC’s new policy of open access, we review FERC’s decision in terms of whether or not it has acted arbitrarily and capriciously. Although Indicated Shippers assert that it is both unfair and illegal to set the Interruptible rate at a rate equal to the 100% Load Factor rate, the base rate for Firm Transportation, we hold that FERC’s decision is not arbitrary and capricious as their articulated reason for setting the Interruptible Transportation rate equal to the 100% Load Factor rate is based on relevant factors, and we find this adequate to support the Northern pricing schedule.

Allocation of Storage, Transmission and Transportation Costs

Indicated Shippers challenge the inclusion of (i) storage costs for storage of natural gas in the Market Area, (ii) transportation costs for transportation services provided by other pipelines to transport natural gas into the Market Area Grid, and (iii) transmission costs incurred by Northern for its own transmission pipeline system. The basis of their appeal is that because FERC allowed Northern to allocate these expenses on a per-unit basis, thus charging Sales, Firm and Interruptible customers equally, these expenses have not been properly allocated by FERC among Northern’s customers.

On May 27, 1986, Northern filed with FERC its Reply Comments in support of its Offer of Settlement. 40 Northern therein addressed the inclusion of these expenses in its transportation rates, maintaining that these costs were legitimate pipeline expenses and that the customers benefitted, primarily by having greater access to Northern’s pipeline system in the Market Area.

FERC, in its brief, contends that the Settlement properly allocated these costs on a per-unit basis between Sales, Firm and Interruptible customers. Thus each class of customer is paying, on a per-unit basis, the same for these services. The decision of FERC to allocate these costs on a per-unit basis is a policy decision, which although having factual aspects to it, is nonetheless subject to the arbitrary and capricious standard.

*1031 i. storage

The storage costs involved are for storage of gas in the Market Area Grid. Indicated Shippers complain that there was no evidence which showed that they actually used or benefitted from the storage service and therefore it is unfair to have storage costs included in the fee structure. We do not agree.

Northern runs the Market Area Grid as a reservoir. This requires the continual storage of excess natural gas in order to guarantee that the reservoir can always meet the natural gas demands of the Market Area. The service that the Indicated Shippers are given is one of immediate access to a specified quantity of natural gas and this entails the cost of “storage.”

The Indicated Shippers question whether there was sufficient evidence showing how the storage costs were included in the transportation rates and whethersforage is in fact provided as part of the transportation service.

Regarding the allocation of storage expenses among sales and transportation users, FERC has articulated a reason for the per-unit charge which we find to be adequately supported. As discussed above, FERC has authorized Northern to charge sales and transportation customers the same on a per-unit basis because both types of customers benefit equally from the services. Storage, third party transportation and transmission costs all serve to expand the space available on Northern’s Market Area Grid system which benefits uniformly sales and both types of transportation customers. It is, therefore, reasonable to allow these costs to be recovered on a per-unit basis.

We do not see any validity also in the argument that storage should be charged to sales customers only because transportation customers do not use storage. The Indicated Shippers do in fact benefit from storage because storage helps to keep the pipeline system free for transportation customers and allows for speedier access to the transportation customer’s quantity of natural gas.

ii. Transportation Costs for Third Party Transportation of Natural Gas Into the Market Area Grid

In addition to Northern’s mainline pipeline, the Market Area Grid is fed by pipelines owned by other operators. These other pipelines bring in natural gas from non-Northern natural gas fields. Northern finds that this third party transportation service is necessary to help keep the reservoir filled. With FERC’s approval, Northern has allocated these costs on a per-unit basis among the sales and transportation customers. Indicated Shippers complain that they are being charged for a service that does not benefit them.

Although the matter of the allocation of transportation charges for service provided by other pipelines to Northern for transportation into the Market Area Grid is a little thornier, we still find a reasoned basis for FERC’s decision. As with storage, sales and transportation customers bear the same per-unit costs of third party transportation.

FERC’s decision to allow Northern to charge transportation customers the same as sales customers on a per-unit basis for third party transportation is similarly supportable. Northern advanced a reason that FERC found to be acceptable, that Firm Sales customers were expected to convert some of their sales service to Firm Transportation. Northern therefore allocated costs in general on the same per-unit basis in the reservation fee and commodity charge for Firm Transportation 41 as in the demand and commodity charges for Firm Sales. FERC accepted that this was the most efficient way to deal with the shift of customers from Firm Sales to Firm Transportation. Order No. 436 has essentially created a new class of service, open access transportation both firm and interruptible, and Northern has adapted its Firm Sales rate structure, including the per-unit cost allocation of these types of charges, to the *1032 new transportation rate structures. FERC found that both classes of transportation customers in general would benefit from third party transportation because of greater capacity within the pipeline and that it was therefore acceptable to charge transportation customers for third party transportation on a per-unit basis. We hold that FERC has acted reasonably.

in. Transmission Costs

Transmission costs are the costs incurred by Northern in maintaining its transmission pipelines. 42 Indicated Shippers again complain only on the basis that the record reflects no reason for the inclusion of these charges because Northern did not provide a breakdown of costs between Sales, Firm and Interruptible Transportation customers.

Again, we find that the allocation of costs chosen by Northern and approved by FERC, the per-unit basis, as opposed to the method desired by the Indicated Shippers, the allocation of these charges to the Sales customers on the basis that Transportation customers do not use them, is supportable because capacity in and access to the Market Area Grid is increased.

The “Postage Stamp" Rate

Pricing for transportation within the Market Area has been converted from a zone based system to a postage stamp system. Northern’s postage stamp rate structure refers to an all-inclusive fee for the transportation of natural gas between points in the Market Area Grid as opposed to a distance based fee structure. Formerly, the Market Area was divided into zones and customers were charged according to how many zones were traversed.

FERC and Northern contend that because the Market Area Grid is run as a reservoir in which natural gas flows by displacement rather than by intentional routing between points, distance based transportation charges are not appropriate as a pricing formula in the Market Area. A transportation customer is not taking its “own” natural gas at the point of delivery in the Market Area, rather it is just entitled to a specified amount of natural gas without regard to where it came from or how far it was transported. FERC, therefore, had a reasonable basis for deciding that a distance based pricing mechanism was inappropriate in the Market Area.

Seasonal Pricing

Indicated Shippers next claim that FERC erred in not requiring seasonal or off peak pricing for the pipeline. We do not agree.

In 1986, FERC ruled that Order No. 436 does not “require pipelines to establish peak and off-peak rates. Instead, the provision only requires pipelines to establish rates that ‘reasonably reflect any material variation in the cost of providing service.’ ” Texas Eastern Transmission Corp., 36 FERC ¶ 61,260 at 61,705 (1986) (citations omitted).

As stated in the preamble to Order No. 436 and again in Texas Eastern, there is no mandatory requirement to have seasonal rates. Rather, the question is “whether ... costs of providing service in the peak period differs materially from ... costs in the off-peak period.” Id.

Although in his dissent, Commissioner Stalon makes an impressive economic argument for the proposition that Northern ought to be required to provide seasonally differentiated rates, that is not the specific issue. Rather, was there any basis in the record which would have required FERC to order such rates. Neither the dissent nor the parties have cited to us such a basis in the record, and we have not discovered one in our own reading. We therefore find no merit in the argument that FERC ought to have ordered seasonally differentiated rates.

*1033 Projected Units for Firm and Interruptible Service

Indicated Shippers argue that FERC erred in not requiring Northern to file separate projected units of service for Firm and Interruptible service. The establishment of separate projected units of service for Firm and Interruptible service is important in that transportation rates are based on projected units of service. 43 For example, fixed costs not recovered in the reservation fee are then allocated between Firm and Interruptible Transportation customers on the basis of projected volumes. 44 We do not reach this issue, however, since Indicated Shippers did not adequately preserve it for appeal.

Section 19 of the Natural Gas Act 45 is very specific about the Court’s jurisdiction on appeal. A case is properly before us only after FERC has issued an original decision and a decision on the petition for rehearing. This Court, furthermore, may only hear those issues that were raised in the petition for rehearing. Our reading of the petition for rehearing convinces us that Indicated Shippers did not preserve the issue for our review.

In its original decision, FERC explicitly stated that none of those commenting on the proposed settlement objected to the lack of definitive allocation between Firm and Interruptible transportation. 46 Indicated Shippers were thus on notice that a specific objection was necessary. Although Indicated Shippers assert that they did object in their petition for rehearing, the objection was not specific enough to satisfy the strict standard. 47 We thus hold that we do not have jurisdiction to respond to the Indicated Shippers explicit contention on appeal that FERC erred in not requiring Northern to allocate capacity between Firm and Interruptible transportation.

Conclusion

Given that we are dealing primarily with questions of policy and the implementation of the new open access transportation order, the underlying consideration for our review is to determine whether FERC has indeed reached a decision arbitrarily. Indicated Shippers have not convinced us that FERC has acted arbitrarily.

FERC is not required to hold evidentiary hearings where only questions of law and policy are matters in controversy. We are dealing here with a new regulatory scheme which seeks to foster competition in the transportation and sale of natural gas. There is no precise precedent either in prior decisions or in available technical data for much of what FERC has done in the orders under review, and Indicated Shippers have not cited preexisting substantial evidence which FERC ought to have considered. Indeed, the arguments that Indicated Shippers make to us are ones of policy and not primarily ones of fact. In the evidentiary vacuum that must naturally exist when an entirely new regulatory scheme is being instituted there is likely to be much experimentation and the primary considerations are of policy and law, not substantial evidence.

Indicated Shippers also contend that FERC has acted arbitrarily and in a manner inconsistent with its own decisions. *1034 They cite to us a FERC decision of March 1, 1988 in which FERC ordered that an evidentiary hearing be held regarding the 100% Load Factor rate, interruptible transportation rate structure, the treatment of storage costs and a postage stamp rate system. 48 Obviously, Southern Natural (March 1, 1988) was not in existence at the time FERC handed down its decision (December 22, 1986) and denied rehearing (November 9, 1987). It was not arbitrary and capricious at that time for the Commission not to have followed a decision then not in existence. Just as obviously, the Indicated Shippers did not nor could not, object to that in their petition for rehearing. When FERC reached its decision in the instant case, in the judgment of the Commission, an evidentiary hearing would not have developed any substantial evidence one way or the other that would have benefitted FERC in the decision-making process. Of course the experience of Northern, as it operates under the new regulatory scheme and the orders under review, will provide technical data and practical experience concerning how many of these contested policies will actually operate. Evidentiary hearings in other cases would therefore not benefit FERC in reaching decisions about other pipeline systems, and ultimately about Northern Natural Gas and the Indicated Shippers as well, in the next round of rate hearings.

What we must look to most of all is not whether FERC has based its decision on substantial evidence, although when such evidence is available FERC clearly must do so, but whether FERC has handed down a decision that is “just and reasonable.” Given the circumstances, we find that it has.

AFFIRMED.

. Amoco Production Company; Arco Oil and Gas Company (a division of Atlantic Richfield Co.); Chevron U.S.A., Inc.; Exxon Corporation; Mobil Oil Corporation; Mobil Producing Texas & New Mexico, Inc.; Mobil Exploration & Producing Southest, Inc.; and Mobil Exploration and Producing North America, Inc.

. Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Order No. 436, 50 Fed. Reg. 42,408 (1985), FERC Statutes and Regulations, Regulations Preambles 1982-1985 ¶ 30,665; reh'g granted in part and denied in part, Order No. 436-A, 50 Fed.Reg. 52,217 (1985), FERC Statutes and Regulations, Regulations Preambles 1982-1985 ¶ 30,675; reh'g granted in part, Order No. 436-B, 51 Fed.Reg. 6,398 (1986), FERC Statutes and Regulations ¶ 30,688; reh’g denied, Order No. 436-C, 51 Fed. Reg. 11,566 (1986), 34 FERC ¶ 61,404; reh'g denied, Order No. 436-D, 51 Fed.Reg. 11,569 (1986), 34 FERC ¶ 61,405; reconsideration denied, Order No. 436-E, 51 Fed.Reg. 1,156 (1986), 34 FERC ¶ 61,403; reversed in part and remanded, Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C.Cir.1987), cert. denied, - U.S. -, 108 S.Ct. 1469, 99 L.Ed.2d 698 (1988); on *1025 remand, Order No. 500, 52 Fed.Reg. 30,334 (1987), FERC Statutes and Regulations ¶ 30,761; modified, Order No. 500-A, 52 Fed.Reg. 39,507 (1987), FERC Statutes and Regulations ¶ 30,770; modified, Order No. 500-B, 52 Fed.Reg. 39,630 (1987), FERC Statutes and Regulations ¶ 30,772; modified further, Order No. 500-C, 52 Fed.Reg. 48,986 (1987), FERC Statutes and Regulations ¶ 30,786; modified further, Order No. 500-D, 53 Fed.Reg. 7,893 (1988), FERC Statutes and Regulations ¶ 30,800; reh’g denied, Order No. 500-E, 53 Fed.Reg. 16,859 (1988), 43 FERC ¶ 61,234; modified further, Order No. 500-F, 53 Fed.Reg. 50,924 (1988), FERC Statutes and Regulations ¶ 30,841; reh’g denied, Order No. 500-G, 46 FERC ¶ 61,148 (1989).

. Pipeline operators, through high fees, want to shift to the "outsiders” seeking transportation service as much of the burden as possible of owning and operating a pipeline while transportation customers want as low a rate as possible in order to keep their natural gas competitive with the natural gas marketed by the pipeline operators.

. In addition to Norther’s mainline, Northern supplies the Market Area Grid with natural gas purchased from fields in Canada, Colorado and Wyoming. The natural gas is transported on other pipelines such as Great Lakes, Northern Border and Trailblazer, who are paid by Northern to bring the natural gas to Northern's Market Area Grid.

.Natural Gas Act, 15 U.S.C. §§ 717-717w.

. Natural Gas Policy Act, 15 U.S.C. §§ 3301-3432.

. FERC adopted Order No. 436 because it determined that the refusal of a pipeline to transport natural gas for a third party, where such transportation would displace the pipeline’s own sales in its capacity as a gas merchant, was "unduly discriminatory" under § 5 of the Natural Gas Act, 15 U.S.C. § 717d.

. 50 Fed.Reg. 42421.

. FERC can authorize transportation by either individual certificates where each transaction must be certified before service commences, or by granting a general authorization to transport which is referred to as self-implementing transportation. Natural Gas Act, § 7(c), and the Natural Gas Policy Act, § 311.

. Sales gas is the pipeline's own natural gas that it transports in its capacity as a natural gas merchant.

. Transportation gas is natural gas that is not owned by the pipeline but is transported by the pipeline for a third party in the pipeline’s capacity as a carrier.

. Northern Natural Gas Co., 33 FERC ¶ 61,067 (1985), reh’g denied, 34 FERC ¶ 61,363 (1986).

. In the context of a FERC proceeding, a "settlement” is an agreement between FERC and the challenging party. Under Rule 602, other parties must be notified and have an opportunity to respond. 18 CFR 385.602. Technically, as in the instant case, the settlement is between FERC and Northern, and not between Northern and the Indicated Shippers.

. A Firm Shipper has paid a "reservation fee” which guarantees the Firm Shipper access to a specific amount of volume space in the pipeline. An Interruptible Shipper pays on a fee per use basis and is not guaranteed access to the pipeline.

. Northern Natural Gas Co., 36 FERC ¶ 63,024 at 65,085 (1986).

. The modifications made by FERC before it accepted the Northern Settlement are not relevant to the instant appeal.

. Northern Natural Gas Co., 41 FERC ¶ 61.158 at 61,398.

. Northern Natural Gas Co., 37 FERC ¶ 61,272 at 61,810. The question as to whether or not the projections were in fact objected to is dealt with below. Infra., Projected. Units for Firm and Interruptible Service.

.The Market Area was divided into transportation zones and the transportation fee was determined by the number of zones traversed. The zones have been amalgamated into a single Market Area zone for which the postage stamp fee applies. The Market Zone and the Market area are geographically identical and will be referred to hereinafter as the Market Area.

. Northern Natural Gas Co., 41 FERC ¶ 61,158 at 61,397.

. Id.

. Minnesota v. FERC, 734 F.2d 1286, 1288 (8th Cir.1984).

. Id.

. See Permian Basin Area Rate Cases, 390 U.S. 747, 791-792, 88 S.Ct. 1344, 1372-1373, 20 L.Ed.2d 312, 350 (1968).

. Natural Gas Act, 15 USC § 717c.

. 18 C.F.R. § 284.7(c)(1) (1988).

. 18 C.F.R. § 284.7(c)(2) (1988).

. 18 C.F.R. § 284.7(c)(3) (1988).

. 18 C.F.R. § 284.7(d)(1) (1988).

. 18 C.F.R. § 284.8(d) (1988).

. 18 C.F.R. § 284.7(d)(2) (1988).

. 18 C.F.R. § 284.9(D) (1988).

. Northern Natural Gas Co., 37 FERC ¶ 61,272 at 61,811 (1986).

. The FERC Brief defines 100% Load Factor Rate as the rate equal to "the total per-unit charges that would be paid for firm transportation if the firm shipper consistently transported 100% of the amount of the capacity that it reserved." FERC Brief p. 15.

. Process Gas Consumers Group (PGC), inter-venors in support of Indicated Shippers, raise the additional argument that the 100% load factor rate is anticompetitive. We do not reach the issue because § 19 of the Natural Gas Act prevents us from considering an argument raised on appeal by an intervenor that was not raised below. See Infra., Projected Units for Firm and Interruptible Service, and United States Gas Pipe Line Co. v. FERC, 824 F.2d 417, 434-436 (5th Cir.1987) (The Court relied on § 19, F.R.A.P. Rule 15(a) and Local 5th Circuit rule to bar intervenor from raising new issue before 5th Circuit.)

.FERC argues, in essence, that the fee paid should be looked at in the context of the entire potential fee paid. In other words, starting at the point where the reservation fee is charged but no reserved capacity is utilized, the Firm shipper has paid a premium for reserved service. The Firm Shipper’s fee comes down in relation to that of the Interruptible Shipper’s fee as more of the reserved capacity is utilized. At the point where the Firm Shipper is using all of the reserved capacity, the 100% Load Factor, the fees become equivalent. Thus, as the Firm *1030 Shipper uses more and more of its reserved capacity, the risk shifts from the Firm Shipper— which bears the risk that it will effectively utilize all of its reserved capacity — to the Interrup-tible Shipper — which has the increasing risk that it will not be able to ship its natural gas.

. The methodology of rate structuring generally employed by FERC allocates fixed costs incurred in operating and maintaining a pipeline to the Demand or Reservation portion of the charge, and costs associated with the actual commodity being transported to the Commodity Charge. What Interruptible Shippers ask, in essence, is that the Interruptible Transportation rate be set at the level of the Commodity Charge alone. To do so, however, would allow Inter-ruptible Shippers to avoid paying fixed costs incurred in the transportation of their natural gas. To the extent that the Interruptible Shipper receives free transportation, it will be subsidized by the Firm Shipper. See Our discussion in Designer Rates supra.; Texas Eastern Transmission Corp., 37 FERC ¶ 61,260 at 61,703 (Fixed costs include, among other things, return on equity, related income taxes, depreciation costs, labor costs incurred in operating and maintaining the pipeline, debt costs, and other taxes and are costs properly allocated to Inter-ruptible Transportation.).

. The Reply Comments were filed in response to Comments filed by various other parties in the proceeding.

. Including, by extension, the Interruptible Transportation rate because the 100% Load Factor rate is the basis for the Interruptible Transportation rate.

. A transmission system is a system of pipelines "installed for the purpose of transmitting gas from a source or sources of supply to one or more distribution centers, or to one or more large volume customers, or a pipeline installed to interconnect sources of supply.” Regulation of the Gas Industry, Vol. 3, Glossary of Terms, GL-15'7, American Gas Association.

. 18 C.F.R. § 284.7(d)(2) (1987).

. Id.

. 15 U.S.C. § 717r(a) and (b).

. Northern Natural Gas Co., 37 FERC ¶ 61,272 at 61,810.

. In their petition for rehearing, Indicated Shippers never specifically challenged the lack of separate figures. They challenged Northern for failing to state separately the allocation of fixed costs between Firm and Interruptible transportation. In their Petition for Rehearing, Indicated Shippers criticized Northern for (i) not identifying which costs were capacity related and ought to have been included in the reservation fee, (ii) not providing a justification for the allocation of the remaining fixed costs, and (iii) not stating separately its costs attributable to providing both Firm and Interruptible transportation. Indicated Shipper’s criticisms regarding the allocation of costs assumes an allocation of capacity between Firm and Inter-ruptible transportation, but we find that this is not adequate to raise the specific issue of inadequate projections of capacity or use. See supra note 36.

. See Southern Natural Gas Co., 42 FERC ¶ 61,261 (1988).