Appendix — California Co. v. Federal Power Commission

Supreme Court, U.

MICHAEL RODAK, JR.

FILED w

MAR LL 9T6

CLERK

In the Supreme Court of the

United States

Ocroser Term, 1975

No. €5-1289

THe CALIFORNIA COMPANY,

A Division of Chevron Oil Company,

Petitioner,

VS.

FrpERAL PowEerR COMMISSION,

Respondent.

Appendix to

Petition for a Writ of Certiorari to the

United States Court of Appeals for the Fifth Circuit

SORG PRINTING COMPANY OF CALIFORNIA, 346 FIRST STREET, SAN FRANCISCO 94105

APPENDIX A

APPENDIX B

APPENDIX C

APPENDIX D

APPENDIX E

TABLE OF CONTENTS

Opinion of United States Court of Appeals

for the Fifth Circuit in Shell Oil Company v.

Federal Power Commission (National Rate

Cases for New Gas), 520 F.2d 1061, de-

cided October 14, 1975.

Opinion and Order of the United States

Court of Appeals for the Fifth Circuit

Denying Certain Petitions for Rehearing in

Shell Oil Company v. Federal Power Com-

mission (National Rate Cases for New Gas)

525 F.2d 1063, Decided January 14, 1976.

Opinion No. 699 of the Federal Power

Commission, Opinion and Order Prescribing

Uniform National Rete for Sales of Natural

Gas Produced from Wells Commenced on

or After January 1, 1973, and New Dedica-

tions of Natural Gas to Interstate Commerce

on or After January 1, 1973 (Issued June

21, 1974)

Opinion No. 699-H of the Federal Power

Commission, Opinion and Order on Rehear-

ing Affirming in Part and Modifying in Part

and Denying in Part Petitions for Rehearing

(Issued December 4, 1974)

Sections 4, 5, 7 and 19 of the Natural Gas

Act of 1938, 52 Stat 821-833, as Amended

15 U.S.C. Sections 717¢c, 717d, 717f and

717r.

APPENDIX A

OPINION OF UNITED STATES COURT OF APPEALS FOR THE

FIFTH CIRCUIT IN SHELL OIL COMPANY V. FEDERAL POWER

COMMISSION (NATIONAL RATE CASES FOR NEW GAS), 520

F.2d 1061, DECIDED OCTOBER 14, 1975

[1061]*

*Bracketed numbers indicate pages in 520 F.2d.

SHELL OIL COMPANY et

al., Petitioners,

Vv.

FEDERAL POWER COMMISSION,

Respondent, and consolidated

cases.*

In re NATIONAL RATE CASES

FOR NEW GAS

Nos. 74-3330, 74-4036, 74-4040, 74-4044,

74-4038, 74-4042, 74-4147, 75-1396, 74-

4233, 75-1123, 75-1164, 75-1246, 75-1266,

75-1268, 75-1270, 75-1614, 75-1620, 75-

1615, 75-1617, 75-1616, 75-1618, 75-1619,

75-1621 to 75-1623, 75-1499, 75-1500, 75-

1590, 75-1756.

*In which the Federal Power Commission is Respondent and

the following are Petitioners:

Rodman Corp., 74-4036, 4040, 4044, 4038, 4042; Texas Eastern

Transmission Corp. and Transwestern Pipeline Co., 74-4147,

75-1396; General American Oil Co. of Texas, 74-4233; Continental

Oil Co., 75-1123; Superior Oil Co., 75-1164; Placid Oil Co. and

Hunt Oil Co., 75-1246; Ipexeo Oil Co., 75-1266; Texas Production

Co., 75-1268; Freeport Minerals Co., 75-1270; Associated Gas Dis-

tributors, 75-1614, 1620; James Abourezk, 75-1615, 1617; American

Publie Gas Association, 75-1616; P> blie Service Commission of

New York, 75-1618; Gulf Oil Corp., «0-1619; Sohio Petroleum Co.,

75-1621: Amoco Production Co., 75-1622; United Distribution Com-

panies, 75-1623; Kerr-MeGee Corp., 75-1499; Phillips Petroleum

Co., 75-1500; Exxon Corp., 75-1590; and Texaco, Ine., 75-1756.

A-l

United States Court of Appeals,

Fifth Cireuit.

October 14, 1975.

[1064]

Petitions for Review of Orders of the Federal Power

Commission.

Before BELL, CLARK and RONEY, Cireuit Judges:

RONEY, Cireuit Judge:

On this review of consolidated cases entitled National

Rate Cases For New Gas, we sustain the Federal Power

Commission's establishment of a national rate for juris-

dictional wellhead sales of natural gas.’ In so doing, for the

first [1065] time in this Cireuit, we give judicial imprimatur

to the promulgation of a rate order through rulemaking

procedures in contrast to formal adjudicatory procedures;

we sustain a wational rate for wellhead sales of natural

gas in contrast to the individual producer rates and the

area rates that have heretofore been approved; and we

hold that the rate structure prescribed withstands various

attacks of the producer, purchaser and consumer petitioners

against diverse findings and conclusions of the Commis-

sion. In sum, we hold the petitioners have failed to show

1. Under review here are a series of orders of the Federal

Power Commission issued in The National Rate Proceeding, Docket

No. R-3S89-B; Opinion No. 699 issued on June 21, 1974; Opinion

No, 699-A, issued on August 2, 1974; Opinion No. 699-B, issued

on September 9, 1974; Opinion No. 699-F, issued on November 7,

IN74: Opinion No, 699-11, issued on December 4, 1974; and Opinion

No, 699-1. issued January 7, 1975.

The substantive issues in this proceeding have not previously

been before this Co mt. However, on February 20, 1975, the Court

issued an opinion and order determining that it had jurisdiction

to review these orders and consolidating the various review peti-

tions under the tithe National Rate Cases For New Gas under

Docket No. 74-3330, Shell Oil Co. v. FPPC, 509 F.2d 176 (5th Cir.

1975).

A-2

either that the rate structure is unjust and unreasonable,

under the limited judicial review permitted this Court, or

that the Commission proceeded in disharmony with statu-

tory and judicial requirements.

FACTUAL BACKGROUND

The history of producer regulation under the Natural

Gas Act has often been recounted in judicial opinions,

necessitating here only a brief statement of the historical

background of this national rate proceeding? From 1938

when Congress passed the Natural Gas Act, 15 U.S.C.A.

§ 717 et seq., until 1954, the Federal Power Commission

eschewed regulation of the price paid to the producer at

the wellhead for natural gas. The Commission viewed its

jurisdiction as limited to regulation of the pipelines which

transported and sold natural gas in interstate commerce.

The number of companies which the Commission regulated

was fairly small. The regulation of the pipelines lent itself

to the traditional cost-of-service mode of utility regulation

on an individual producer basis.

In 1954 the Supreme Court ruled that the FPC was re-

quired to regulate wellhead sales of natural gas by inde-

pendent producers, defining such producers as “natural

gas compan(ies]” within the meaning of § 2(6) of the Act,

15 U.S.C.A. § 717a(6). Phillips Petroleum Co. v. Wisconsin,

347 U.S. 672, 74 S.Ct. 794, 98 L.Ed, 1035 (1954). Inde-

pendent producers are those producers which do “not

engage in the interstate transmission of gas from the

2. See, e. g., Mobil Oil Corp. v. FPC, 417 US, 283, 300-310,

94 S.Ct. 2328, 41 L.Ed2d 72 (1974); Permian Basin Area Rate

Cases, 390 U.S. 747, 755-766, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968)

[Permian]; Southern Lowisiana Area Rate Cases, 428 F.2d 407,

415-421 (%th Cir.), on reh., 444 F.2d 125 (5th Cir.), cert. denied,

400 U.S. 950, 91 S.Ct. 243, 27 L.Ed.2d 257 (1970).

A-3

producing fields to consumer markets and [are] not affil-

iated with any interstate natural-gas pipeline company.”

Phillips at 675, 74 S.Ct. at 795. The jurisdiction recognized

by Phillips increased the number of Commission-regulated

entities by over thirty-three hundred.* This increase in

regulatees made the burden of individual regulation un-

feasible and forced the Commission to seek an alternative

method. Area rate regulation resulted.

The Commission instituted proceedings to regulate the

wellhead prices charged by independent producers for

certain geographical areas throughout the United States.

The Supreme Court held this to be permissible under the

Natural Gas Act in its landmark area rate regulation

decision, Permian Basin Area Rate Cases, 390 U.S. 747,

88 S.Ct. 1344, 20 L.Ed.2d 312 (1968). The guidelines set

forth in that case have since been used by all Courts of

Appeals called upon to review Commission area rate orders.

See, e. g., Southern Louisiana Arca Rate Cases, 428 F.2d

407 (5th Cir.), on reh., 444 F.2d 125 (5th Cir.), cert. denied,

400 U.S. 950, 91 S.Ct. 243, 27 L.ked.2d 257 (1970) [So.La. 1}.

[1066] The Commission eventualiv delineated seven geo-

graphical areas and established ceiling prices for natural gas

sold from those areas by independent producers.* Pipeline

producers and pipeline affiliated producers were subject to

8 See Permian. 390 U.S. at 757 n. 12; 88 S.Ct. 1344.

4. The existence of these geographical areas was noted by the

Supreme Court, in a footnote in its most recent area rate review,

Mobil Oil Corp. v. FPPC, 417 USS, 285 289-290 n. 3, 94 S.Ct. 232

41 L.Ed2d 72 (1974), which footnote when updated shows the

status of the rate proceedings for the various areas as follows:

1. Permian Basin Area

Opinion Nos. 468 and 468-A, 34 FPC 159 and 1068,

respectively (1965), aff'd, Permian Basin Arca Rate Cases,

390 US. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1965).

New rates for this area were established in:

A-4

different rate regulation. The Commission has now decided

that what it once hoped would be the mainstay of producer

rate regulation, the area rate structure, is net the panacea

it had sought. Consequently, in this case we are asked to

review the next experimental phase in producer regulation,

a national rate for new natural gas.

Opinion Nos. 662 and 662-A, 50 FPC 390 (1973) (petition

for review withdrawn).

2 Southern Louisiana Area

Opinion Nos. 546 and 546-A, 40 FPC 530 and 41 FPC 301,

respectively (1968), aff'd, Southern Lowsiana Area Rate

Cases, 428 F.2d 407 (5th Cir.), on reh., 444 F.2d 125 (5th

Cir.), cert. denied, 400 U.S. 950, 91 S.Ct. 248, 27 L.Ed.2d

257 (1970).

New rates for this area were established in:

Opinion Nos. 598 and 598-A, 46 FPC 86 and 633, respee-

tively (1971), aff'd, Placid Oil Co. v. FPC, 483 F.2d 880

(5th Cir. 1973), aff'd sub nom., Mobil Oil Corp. v. PPC, 417

U.S. 283, 94 S.Ct. 2328, 41 L.Ed.2d 72 (1974)

3. Texas Gulf Coast Area

Opinion Nos. 595 and 595-A, 45 FPC 674 and 46 FPC 827,

respectively (1971), rev'd and remanded, Public Service Com-

mission v. FPC, 159 U.S.App.D.C. 172, 487 F.2d 1043 (1973),

vacated and remanded sub nom., Shell Oil Co, v. Public Serv-

ice Commission, 417 U.S. 964, 94 S.Ct. 3166, 41 L.Ed.2d 1136

(1974).

4. Hugoton-Anadarko Area

Opinion No. 586, 44 FPC 761 (1970), aff'd, Hugoton-

Anadarko Area Rate Case, 466 F.2d 974 (9th Cir. 1972).

5. Other Southwest Area

Opinion Nos. 607 and 607-A, 46 FPC 900 and 47 FPC 99,

respectively (1971), aff'd, Other Southwest Area Rate Case

(OSWAI), 484 F.2d 469 (Sth Cir. 1973), cert. denied, 417

U.S. 973. 94 S.Ct. 3180, 41 L.Ed.2d 1144 (1974).

6. Appalachian and Illinois Basin

Order Nos. 411, 411-A and 411-B, 44 FP 1112, 1334 and

1487, respectively (1970) (no appeal).

The Commission declined to establish new area rates for

this area in Opinion No. 639, 48 FPC 1299 (1972), aff'd,

Shell Oil Co. v. FPC, 491 F.2d 82 (5th Cir. 1974).

7. Rocky Mountain Area

Opinion Nos. 658 and 658-A, 49 FPC 924 and — FPC —,

respectively (1973) (petition for review withdrawn).

A-5

STRUCTURE OF THE NATIONAL RATE

FOR NEW GAS

Despite protestations from many producers and pipelines,

the Commission adhered to cost as the basis for the new

national rate. The FPC utilized the methodology developed

by it in Area Rate Proceeding (Permian Basin), 34 FPC

159 (1965), aff'd, Permian Basin Area Rate Cases, 390

U.S. 747, 88 S.Ct. 1344, 20 L.Fd.2d 312 (1968), as modified

in the second Southern Louisiana proceeding, Area Rate

Proceeding (Southern Louisiana), 46 FPC 86 (1971), aff'd,

Placid Oil Co, v. F PC, 483 F.2d 880 (5th Cir. 1973), aff’d

sub nom., Mobil Oil Corp. v. FPC, 417 U.S. 283, 94 S.Ct.

2328, 41 L.Ied.2d 72 (1974) [So.La. II]. Basically the rate

was determined by projecting the average cost of finding

and producing “new gas,” 7. e., gas discovered after Janu-

ary 1, 1973, over the estimated life of the producing wells

and adding a 15 percent annual rate of return. Historical

items of cost were predicted for the future to attempt to

insure that the producer would recover its actual expenses

at the time work is done. Relating these estimated costs to

the commonly accepted unit of gas sold to the consumer

results in a maximum allowable rate for natural gas in

cents per Mef, 7. ¢., thousand cubic feet.

Although the rate determined in this proceeding was

based on the cost of finding nonassociated natural gas, 7. e.,

gas occurring independently from other extractable forms

of petroleum, casing-head gas is also eligible for the new

rate, even though it might cost less to pro- [1067] duce. The

(‘omimission has long refused to compute separately the cost

of casing-head gas hecause of the difficulty in allocating the

production costs between such gas and the oil produced

from the same well. See, e. g., Permian, 390 U.S. at 761, 88

S.Ct. 1344. Likewise, this national rate will, under certain

A-6

conditions, apply to substantially increase the price of “old”

gas as well, even though the cost of such pre-January 1978

gas did not figure in the computation of the national rate.

While sales of pipeline producers previously had been

vintaged by the date when the natural gas lease was acquired

by the pipeline, the Commission decided in Opinion No.

699-H to allow pipeline producers to be eligible for the new

rate on the same basis as independent producers. The Com-

mission saw no reason to treat wells commenced by a pipe-

line any differently than those commenced by independent

producers for costing purposes.

In arriving at an ultimate rate figure under this method,

the Commission was required to resolve many disputed

issues of “pure” fact, assign values to rate components hased

on a combination of fact and policy considerations, and

make policy decisions regarding which components to in-

clude, where to include them, and how they should be in-

cluded. Thus, while the final result is a figure which must

have some mathematical relationship to these various con-

siderations, the premises from which the figure is derived

are far from mathematically exact. Because of this elasticity

in the rate equation, courts traditionally refuse to be drawn

into choosing “numbers” which actually represent policy

choices properly available to the Commission, the govern-

mental unit to which Congress has primarily committed the

regulation of the natural gas industry.

The Commission developed both a “high” and a “low”

cost figure by making various choices among the alterna-

tives available to it. The overall cost determination was

based on an evaluation of the following components: (1)

Successful Well Cost, (2) Dry Hole Cost, (3) Lease Aequisi-

tion Cost, (4) Cost of Other Production Facilities, (5) Other

Exploration Cost, (6) Exploration Overhead, (7) Produe-

A-?

tion Operating Expense, (8) Net Liquid Credit (subtracted

from costs), (9) Royalty Expense, (10) Recompletion and

Deeper Drilling Cost stipulated, (11) Regulatory Ixpense

(stipulated), (12) Return on Production Investment, and

(13) Return on Working Capital. The Commission did not

include an element of cost for federal income tax but estab-

lished a procedure whereby a producer can gain an increase

for taxes paid upon jurisdictional activities by making an

individual showing that such expense was actually incurred.

Various of these cost components have been attacked on

appeal and will be diseussed more fully hereinafter, but

first a brief description of the FPC methodology may be

helpful.

Like every cost factor, Successful Well Cost must be

converted to cents per thousand cubie feet, the base unit.

Ideally, to do this the Commission would divide the number

of feet drilled in a given year which resulted in finding

nonassociated natural gas into the nonassociated natural

gas reserves discovered as a result of such drilling. The

quotient is called the “productivity” of the drilling and is

expressed in Mef of newly-discovered gas per foot of drilling

(Mef/ft). The cost of drilling a foot of a successful well

(¢/ft) would then be divided by the productivity (Mef/ft)

with the quotient being expressed in the desired unit, cents

per thousand cubic feet (¢/Mef). This computation is not

feasible as described, however, because of the manner in

which data concerning the natural gas industry is collected.

Drilling footage is recorded in the year it occurs, but no

one compiJes reserve additions by wells drilled. Instead,

“reserves added” are computed on a net annual basis, taking

ACEOL ‘eductions in reserves which have been pre-

viously overestimated, Thus, there are variables other than

successful well drilling which affect the net nonassociated

A-8

reserve additions for a giv- [1068] en year. Nonetheless, the

FPC must compute productivity, so it used the only informa-

tion available to it for reserve additions, the American Gas

Association reserve studies and the various footage com-

pilations.

Dry Hole Cost (cost of drilling unsuccessful wells) was

separately computed by dividing the cost per foot drilled

(¢/ft) by the productivity of successful wells (expressed in

Mcf /ft), computed as previously discussed, with the quotient

again being in cents per thousand cubic feet (¢/Mcf). The

figure so obtained was then adjusted upward to reflect the

greater depth and thus higher costs and the offset of higher

success ratio at those depths for gas well drilling as com-

pared to oil well drilling.

Lease Acquisition Cost, expressed in dollars, was reduced

to the base unit, ¢/Mef, by determining the relationship

between total Successful Well Cost and total Lease Acqui-

sition Cost in a given year. The ratio of the former cost

to the latter cost was then multiplied by the previously

determined Successful Well Cost per unit, the result being

Lease Acquisition Cost per Mef.

Cost of Other Production Facilities is the cost of those

production facilities not included in Successful Well Cost.

To convert this cost to the base unit, the Commission

divided total Other Production Facilities Cost by total Sue-

cessful Well Cost and multiplied the unit Successful Well

Cost by the resultant ratio.

Several elements were used in computing Other Explora-

tion Cost: the unit Lease Acquisition Cost component (ex-

pressed in ¢/Mef) was muitipiied by the ratio of total

national Other Exploration Cost to total Lease Acquisition

Cost. Other Exploration Costs are the direct costs, other

than the cost of drilling a dry hole, which are experienced

A-9

in the search for natural gas, These should be distinguished

from the Exploration Overhead, which was separately com-

puted as a component of the rate structure.

Exploration Overhead was derived by multiplying the

sum of unit Dry Hole Cost and Other Exploration Cost by

the ratio of National Exploration Overhead Cost divided

by National Other Exploration Cost, using a multi-year

average.

Production Operating Expense, the daily costs of labor,

energy, and other expenses for operating a successful well,

was calculated by dividing operating expenses for gas

leases by the production from gas leases (expressed in

Mef) to obtain a unit value quotient.

Net Liquid Credit, unlike the other components of the

cost based rate, represents receipt of revenue incident to

the production of natural gas, and, therefore, is a credit

against expenses. In processing natural gas, certain liquifi-

able hydrocarbons, such as propane, butane and ethane are

extracted and liquified. These liquids are then sold and the

experienced revenue from these per Mef of natural gas

was subtracted as the Net Liquid Credit.

Royalty Expense represents the percentage of the gross

receipts which a producer must pay to the landowner for

the privilege of extracting from the reserves underlying

his land. It was computed by applying a percentage to the

gross receipts.

Two cost components were stipulated by the parties,

which stipulations were accepted by the Commission as

representative costs: Reeompletion and Deeper Drilling

Cost and Regulatory Expense. Recompletion and Deeper

Drilling Costs are incurred in rejuvenating old wells to ex-

tend their productive life. Regulatory Expense is the cost

per Met which is directly attributable to the cost of filing

A-10

—

~

required reports, of participating in proceedings such as

the instant one, and of other necessary activities related to

both state and federal regulation.

Return on Production Investment and Return on Work-

ing Capital were computed by applying the annual rate of

return decided upon to certain predicted costs.

Certain of the cost items are included in the “rate base”

upon which the Com- [1069] mission allows the producers to

receive a percentage return on expenses, some are not. The

decision as to which items are properly part of the rate base

for return purposes is one which involves policy as well as

economic considerations. The items which are not included

in the rate base are still recoverable as expenses. The cost

components comprising the rate base, and, therefore, on

which a rate of return is allowed are Successful Wells, Dry

Holes, Lease Acquisition, Other Production Facilities,

Other Exploration, Exploration Overhead, and Recomple-

tion and Deeper Drilling. The remaining items, Production

Operating Expense, Net Liquid Credit, Royalty Expense,

and Regulatory Expense, are treated as annual credits or

expenses. Having decided on which items a return would be

allowed, the Commission computed the unit cost of that

return at a 15 percent annual rate using a discounted cash

flow economic model.

Tn computing all costs to be used in the above-described

model, the FPC recognized that it could not be exact and,

therefore, made a number of different assumptions regard-

ing each component. In this manner the Commission arrived

at the range of what it considered reasonable costs, with a

“low” total cost based primarily on the low assumptions

and a “high” total cost based primarily on the higher as-

sumptions. For example, in computing drilling costs for

the 1973-74 time period for which the rate was designed,

A-11

the “low” cost was actual experienced cost in 1972, whereas,

the “high” cost was the 1972 cost projected by the least

squares regression method in order to account for a rising

trend in drilling costs. Similarly, the important element,

productivity, was computed to produce a high and a low

estimate: as productivity has been declining recently,

longer period (10 years) was av eraged to produce the ow”

cost than was averaged to produce the “high” cost (7 years).

The Commission asserts that it set the 15 percent annual

rate of return high enough above a traditionally non-con-

fiscatory rate of return to put some noncost factors into the

rate to make the interstate market more competitive with

other markets.

Ultimately, the FPC determined that a reasonable rate

could fall between 48 cents and 52 cents, based on all factors.

From this range the Commission chose 50 cents per Mef as

the rate it would allow on jurisdictional natural gas subject

to the No. 699 series of opinions.

A. Ancillary Provisions in the Rate Structure

Besides a determination of the rate and the natural gas

to which it would apply, the Commission’s order contains

a number of ancillary provisions, some of which are impor-

tant to an understanding of the rate structure.

First, the order made provision for special relief in

unusual circumstances where the rate is not sufficient to

recover the cost of producing natural gas already dedicated

to the interstate market. The burden is on the producer with

the above average costs to justify an additional price for

its gas. This is not the only avenue of extraordinary relief

for producers who may be adversely affected by the national

rate structure, however. The FPC has standing regulations

which afford relief to producers who face an increase in

!

A-12

ee ee ar ea a eS

costs. 18 C.F.R. § 2.76 (1974). A producer who is seeking

special relief because of federal income taxes actually paid

may use procedures established in this proceeding for such

relief. Thus, although federal income taxes are not allowed

as a cost in the basic “cost-based” rate, they are recoverable,

if actually paid, by use of a special relief proceeding.

Second, the rate structure provides for a biennial review

of the rate and the rate’s efficacy in accomplishing the goals

which the F PC is seeking to attain. It is the Commission’s

stated policy that any increased rate found just and reason-

able in each biennial review will be allowed for all natural

gas which is subject to the present proceeding.

Third, the rate structure provides for a fixed annual rate

escalation, irrespective of any additional proof of increased

[1070] costs. Under this provision gas subject to this pro-

ceeding is allowed a one-cent per Mef escalation in price as

of January 1 of each year.

B. Scope of the Order

Besides the requirement that the natural gas be pro-

duced within the continental United States, or offshore

thereof, exclusive of Alaska, the current scope of the order

is primarily defined by the interaction of three possible

occurrences relating to natural gas distribution and produc-

tion. If any one of them occurred on or after January 1,

1973, the sales of natural gas from the affected well are

eligible for the new national rate under the Commission’s

regulations. The three sale situations which justify the new

rate were described by the Commission in Opinion No.

699-H:

(i) The sale is made from a well or wells commenced

on or after January 1, 1973;

(ii) Sales made pursuant to contracts for the sale of

natural gas in interstate commerce for gas not

A-15

previously sold in interstate commerce prior to

January 1, 1973, except pursuant to the provi-

sions of 18 C.F.R. §§ 2.68, 2.70, 157,22, or 157.29

(including sales made pursuant to those sections

as modified by Federal Power Commission Order

No. 491, et al.) [temporary emergency sales of

various sorts |, or 18 C.F.R. § 2.75(n), where such

sales are initiated on or after January 1, 1973,

provided that no certificate for the subject sale

has been issued under the optional procedure (18

C.F.R. § 2.75) ;

(iii) Sales made pursuant to contracts executed prior

to or subsequent to the expiration of the term of

the prior contract where the sales were formerly

made pursuant to permanent certificates of un-

limited duration under such prior contracts which

expired of their own terms on or after January

1, 1973, or pursuant to contracts executed on or

after January 1, 1973, where the prior contract

expired by its own terms prior to January 1, 1973.

The propriety of applying the new rate to sales made

under (i), the “wells comn enced” standard, and (ii), new

long-term commitments of natural gas to interstate com-

merce is not questioned in this proceeding.

The application of the new rate to category (iii), sales

made pursuant to renewal contracts of natural gas previ-

ously committed to interstate commerce, is challenged on

this review as unjustifiable.

STANDARD OF REVIEW

It is always necessary to keep in mind the limits of judi-

cial inquiry when we are called upen to review an order

A-1l4

Fe eee ee

aK ee ew i -

issued by the Federal Power Commission, Although these

limits have been variously explicated over the vears, they

have never been diverted from the “end result” test which

finds its genesis in the earliest Supreme Court cases re-

viewing orders under the Natural Gas Act. FPC v. Hope

Natural Gas Co., 320 U.S. 591, 64 S.Ct. 281, 88 L.Md, 333

(1944); FPC v. Natural Gas Pipeline Co. of America, 315

US. 575, 62 S.Ct. 736, 86 L.ld, 1037 (1942). The end result

test was tailored to area rate orders by the Supreme Court

in Permian Basin Area Rate Cases, 390 U.S. 747, 766-767,

791-792, 88 S.Ct. 1344, 20 L.ld.2d 312 (1968). This Court

has, on various occasions, discussed our understanding of

the Permian prescription. See Shell Oil Co. v. PPC, 491

F.2d 82, 85 (5th Cir. 1974) ; Placid Oil Co, v. FPC, 483 F.2d

880, 888-890 (5th Cir. 1973), aff'd sub nom., Mobil Oil Corp.

v. FPC, 417 U.S. 283, 94 S.Ct. 2328, 41 L.Bd.2d 72 (1974) ;

Southern Louisiana Area Rate Cases, 428 F.2d 407, 417-418

(5th Cir.), on reh. 444 F.2d 125 (5th Cir.), cert, denied, 400

U.S. 950, 91 S.Ct. 248, 27 L.ked.2d 257 (1970).

[1] The issue which we must ultimately resolve is

whether the end result [1071] of the orler is “unjust and

unreasonable.” In assessing the facts from which this ulti-

mate conclusion is derived, we are guided by four elements

which delimit the scope of our authority :

(i) the well-known statutory “substantial evidence”

standard, (ii) a judicially recognized “presumption of

validity” implied from the congressional limitation,

(iii) the long-standing “total effect” test of PPC v.

Hope Natural Gas Co., i944, 320 U.S. 591, 64.'S.Ct. 281,

88 L.Ed. 333, and (iv) a “zone of reasonableness” to

compensate for the necessarily imprecise nature of

cost determinations and the inherent difficulty of the

regulatory undertaking.

A-15

Placid Oil Co. v. F PC, supra at 889 n. 6.

The fact that our vision is tunneled does not relieve us,

however, from our duty to look at the Commission order

from a!l angles. The Supreme Court has made clear

. that the responsibilities of a reviewing court

are essentially three. First, it must determine whether

the Commission’s order, viewed in light of the relevant

facts and of the Commission's broad regulatory duties,

abused or exceeded its authority. Second, the court

must examine the manner in which the Commission

has employed the methods of regulation which it has

itself selected, and must decide whether each of the

order’s essential elements is supported by substantial

evidence, Third, the court must determine whether the

order may reasonabiy be expected to maintain financial

integrity, attract necessary capital, and fairly com-

pensate investors for the risks they have assumed, and

vet provide appropriate protection to the relevant

public interests, both existing and foreseeable. The

court’s responsibility is not to supplant the Commis-

sion’s balance of these interests with one more nearly

to its liking, but instead to assure itself that the Com-

mission has given reasoned consideration to each of

the pertinent factors.

Permian Basin Area Rate Cases, supra at 791-792, 88 S.Ct.

at 1373 (emphasis supplied).

In the review of area rate cases, however, our already

narrow scope of review has been tempered even further by

re ognition of the experimental nature of area regulation.

EB. qg., Piacid Ol Co. v. FPPC, supra at 889-890; Southern

Louisiana Area Rate Cases, supra at 418; see Permian

Basin Area Rate Cases, supra passim. The “kid glove”

A-16

review resulting from the “experiment rationale” has led

this Court and the Supreme Court to accept findings and

reasoning by the Commission as adequate, even though both

courts have expressed serious misgivings about the ultimate

accuracy of the FPC’s conclusions. Accordingly, on at least

two oceasions we have “affirmed” or “enforced” FPC orders

while expressing our concern about the marginal adequacy

of the FPC orders. We have specifically reserved to the

Commission the authority to make retroactive changes to

the very orders we “affirmed” as being supported by sub-

stantial evidence. Southern Louisiana Area Rate Cases,

supra at 421, 426 n. 46, 427, 431, 434-444; 444 F.2d at 126-

127. See Shell Oil Co. v. FPC, supra at 87-88. The FPC

responded to our admonition with a more extensive study

of the problem in the Southern Louisiana Area, and the

resultant area rate order was affirmed by both this Court

and the Supreme Court. Placid Oil Co. v. FPC, 483 F.2d

880 (5th Cir. 1973), aff'd sub nom., Mobil Oil Corp. v. FPC,

417 U.S. 283, 94 S.Ct. 2328, 41 L.Ed.2d 72 (1974).

[2] To affirm the action of the Commission on review

here requires continuation of the heightened deference to

the Commission's expertise inherent in the “experiment

doctrine.” Opinions 699 and 699-H assert many factual con-

clusions and regulatory justifications without explicating

for this Court the factual predicates or assumptions upon

which such decisions are based, We have concluded, how-

ever, that national rate regulation is still experimental and

we must [1072] apply a standard of review requiring height-

ened deference to the Commission’s expertise in such experi-

mental regulations.

The first area rate regulation proceedings related to the

Permian Basin Area and began in 1960. Prior to the estab-

lishment of the national rate in this proceeding, the FPC

A-17

had considered area rate structures in ten proceedings in-

volving seven distinct geographical areas, Seven of these

proceedings were the subject of judicial review and com-

ment, with two of those receiving review by both a court of

appeals and the Supreme Court.’ An examination of the

area rate structures and the cases in which they were re-

viewed reveals that the FPC has continued to experiment

with various combinations of contingent escalations, auto.

matie escalation, vintaging, refund workoffs and the like in

an attempt to alleviate the national natural gas shortage

by stimulating exploration and development. At the same

time the Commission has persisted, in spite of the protesta-

tions of the producers, in relying upon a cost-bused rate as

the starting point in an effort to protect the consumer from

exploitation in this time of shortage.

The national rate structure under review is a unique

combination of provisions which, along with the shift to a

national! rate itself, demonstrates that the Commission does

not believe that any of the total rate structures which it

developed in the area proceedings had the desired effect of

providing developmental incentive while preventing exploi-

tation. The Commission has been unsuccessful in generating

additional natural gas reserves for the interstate market

within the framework of its congressional mandate. In the

face of growing demand for natural gas by the intrastate

market, the effort to protect consumer interest as to price

is at odds with the long range consumer interest in main-

taining an adequate supply of natural gas for the interstate

market. Finding and maintaining this point of delicate

balance is a difficult task. Congress has chosen the FPC to

be its surrogate for this responsibility, and our view of

—— ee

5. See footnote 4 supra.

A-18

:

5

;

the agency’s work must take into account the attendant

difficulties to assure that the legislative scheme will be

effectuated.

We must express our regret, however, that the FPC con-

tinues to issue orders which would be inadequate but for

our “kid glove” treatment. Perhaps one reason the Com-

mission has continued to flounder in the sea of area regula-

tion is-its failure to assess the consequences of its various

policies. For example, if it does not have reasonable knowl-

edge of the effect a contingent escalation in price will have,

it ean hardly evaluate the efficacy of having such a provi-

sion in the rate structure. Just as we must consider indi-

vidual elements in our review of an FPC order to insure

that it is supported by substantial evidence, so should the

Commission examine the effect of each when it is deciding

how to compose the rate structure initially. For over four-

teen years the Commission has been experimenting in area

rate regulation and yet it still “supports” many of the

essential elements of its new national rate order with little

more than ipse dizit.

We recognize, of course, that the issues in a review such

as this are not always separate and distinct, but involve

overlapping considerations and resolutions. But a cau-

tionary note should indicate that as experiment lapses into

experience, the courts may well expect the Commission to

justify its policies with reasoned projections of that once-

prototypic policy’s probable net effect. The principle of

stare decisis may only lightly touch the standard of sub-

sequent review.

Therefore, with these principles of review in mind, we

give a limited review to the Commission’s actions.

[1073]

A-19

IS A NATIONAL RATE PERMISSIBLE

UNDER THE NATURAL GAS ACT?

[3] The initial inquiry is whether the Commission has

the authority to establish a national rate under the Natural

Gas Act. It would seem clear that under existing Supreme

Court cases there is no legal impediment to the Commis-

sion’s choosing a national rate as its method of regulation

of wellhead sales of natural gas. In the approval of area

rates, the extent of the area does not appear to have been

a controlling consideration. To a large extent, the nation is

merely a geographically expanded area. The rate set in at

least some of the area rate proceedings was hased on na-

tional data only. The most noteworthy of the Supreme

Court cases in this regard is, of course, Permian itself. See

24) U.S. at 761, 88 S.Ct. 1344. We think that the Sfapreme

Court’s approval of an area rate for new gas based partially

on national data requires us to uphold the legality of a

national rate in this case.

This decision that such rate regulation is permissible

comes with seme misgivings. A national rate exacerbates

the problems noted in Justice Douglas’ dissent from Perm ian

as to the rates set for the relatively small geographical area

involved in that case.

The area rate orders challenged here are hased on

averages, No single producer’s actual costs, actual

risks. actual returns, are known.

The “result reached” as to any producer is not

known.

The “impact of the rate order” on any producer is

not known.

The “total effect” of the rate order on a single pro-

ducer is not known.

A-20

a Sia Ri ea id on ante LIES ATs mm eae NN

Wits oes —

Permian Basin Area Rate Cases, 390 U.S, at 829-830, 88

S.Ct. 1344 (Douglas, J., dissenting) (footnote omitted).

The problem with the legality of any area rate, and most

particularly a national rate, stems from the fact that the

legal role of a reviewing court under the Act involves a

bifurcated examination of the “end result” or consequence

of any FPC rate order: (1) does the order protect the con-

sumer against excessive rates and charges; and (2) is it

consistent with the maintenance of adequaie service in the

public interest. See generally Atlantic Re fining Co. v. Public

Service Commission, 360 U.S. 378, 388, 79 S.Ct. 1246, 3

L.Ed.2d 1312 (1959). If this is our Court’s role, as opposed

to merely preventing confiscation, then it is arguable that

any rate methodology which inherently prevents this Court

from performing its role contravenes the Act. Put another

way, if there can simply never be “substantial evidence” to

support the discretionary exercise of judgment by the Com-

mission, then it could be argued that the method of regula-

tion should be outside the scope of the Act.

The national rate presents such a circumstance. First,

since it is largely “prospective” the rate can hardly he con-

fiseatery because the producers may adjust their programs

within the structure of the national rate in such a manner

to produce the profit which they need, virtually disregard-

ing the Commission’s “reasonable rate of return.” In an in-

dustry with high risks of exploration and development,

prospective rates arguably could never really work “con-

fiscation” in the constitutional sense. If the producers’

geological surveys remain reasonably accurate, they will

usually be able to produce some quantity of gas at a profit

within practically any rate structure. They will simply stay

out of high cost production that would earn less profit than

necessary to attract venture capital. The larger the rate the

A-21

greater would be the exploration for new reserves. The

producers here do not assert the invalidity of the rate on

the ground that it is confiseatory.

Assuming then, that the rate is not confiseatory, the use

of a national rate with biennial review precludes any court

from effective review based on the “end result” of the rate

order. First, because there is never one definitive, lasting

rate determination, the “end result” of Commission action

is in a continuous state of flux. Second, the Commission

itself [1074] makes no evaluation of the “end result” of its

rate order, The Commission concludes that supply and price

are directly proportional, 7. ¢., that an increase in the price

allowed will result in an increase in supply. From this the

Commission reasons that an increase in the price allowed

will of necessity do something to alleviate the natural gas

shortage which everyone recognizes has developed, But the

FPC “found” that there was no way to quantify this rela-

tionship and that there is accordingly no way to determine

just how much any given price increase will affect. the

supply of natural gas. There is no reliable estimate as to

what new gas will be brought to the interstate market be-

cause the Commission reports that such a factually reliable

estimate is impossible. Without any such quantification, it

is simply impossible for this Court to determine if the “end

result” will maintain an “adequate supply in the publie

interest” or not. Going on past experience for area rates

the answer appears to be in the negative, and it is in part

for this reason that the FPC has abandoned area rates.

What basically appears to exist, then, is a method of

regulation by area, approved by the Supreme Court, at

least as an experiment, and a standard of review. similarly

preseribed by that Court, which are s6mewhat incompatible,

The method of regulation prevents quantification of the

A-22

- wm ee re

effects of FPC decisions, with only the most general con-

clusions readily deducible, whereas, this Court is supposed

to examine this unquantifiable “end result” to determine

whether the FPC order is acceptable.

Having decided, however, that we are hound to approve

a national rate method of regulation control of natural gas,

our review of the Commission’s actions must be tailored to

the practical requirements of the circumstances. Little

would be accomplished by on the one hand deciding that a

national rate could be established, while on the other hand

burdening the Commission with procedural and evidentiary

requirements which, though necessary to the legality of

individual or smaller area ratemaking, would either prolong

or complicate the task of the Commission to the point of

impossibility.

DOES RATEMAKING BY THE RULEMAKING PRO-

CEDURE COMPORT WITH STATUTORY RE-

QUIREMENTS AND CONSTITUTIONAL DUE

PROCESS?

The American Publie Gas Association (APGA) chal-

lenges the Comimission’s use of a rulemaking process to set

a national rate for natural gas, arguing that by excluding

adversarial trial procedures such as formal evidentiary

hearings, oral testimony and o.al cross-examination, the

Commission violated both the requirements of the Natural

Gas Act and those of constitutional due process.

In setting a national rate for new gas the Commission

went bevond the rudiments of informal rulemaking. On

April 11, 1973, the Commission issued a notice of proposed

rulemaking, which clearly indicated that the Commission

intended to establish by rule nationwide rates for natural

gas. 38 Fed. Reg, 10014 (1975). The notice made all large

A-23

producers respondents to the ratemaking proceeding, and

provided for the submission of sworn written comments

from all interested parties. Shortly thereafter the FPC

gave notice that it intended to establish a single national

rate for new gas. 38 Fed.Reg. 14295. These Notices of

Rulemaking incorporated Commission cost studies. Pur-

suant to these Notices over eighty parties representing a

broad range of consumer and gas industry interests re-

sponded, submitting such sworn testimony and evidentiary

data as they desired. Parties thereafter submitted reply

comments, this second round of submittals giving them an

opportunity to rebut both Commission and privately-

generated evidence. In addition to accepting copious written

responses to its proposed rulemaking, the Commission held

a public conference on the issues of reserve additions and

drilling footages, and held two days of oral argument on

proposed Opinions Nos. 699 and 699-11.

[1075

In upholding the rulemaking procedures used by the

Commission in tuis proceeding we do not find it necessary

to decide what minimum procedures are necessary under

the Natural Gas Act and the Administrative Procedure Act.

[t is unnecessary to enter the colloquy between the Tenth

and the District of Columbia Cireuits as to whether infor-

mal rulemaking (5 U.S.CLA. $553) or formal evidentiary

hearings (9 U.S.CLA. $$ 596, 557) are mandated by the

Natural Gas Act. Compare Phillips Petroleum Co. v. FPC,

475 F.2d S42 (10th Cir, 1973) (holding that the informa!

rulemaking provision of the Administrative Procedure Act,

oO ULS.CLAL £555. applies to FPC rulemaking) with Mobil

OW Corp. «. FPO. AUST ULS.App.D.C. 235, 483 F.2d 123!

(19723) Chelding that £555 rulemaking is insufficient. but

$$.996, 997 hearings are not necessarily required by the

A-24

UP eee

Natural Gas Act). But see American Public Gas Associa-

tion v. FPPC, 498 F.2d 718 (D.C.1974) (rulemaking to set

area rates did not abuse the Natural Gas Act).

[4,5] The above-described procedural process which is

on review before this Court satisfies even the more stringent

requirements of the formal hearing process, The APGA is

incorrect in arguing that it has a statutory right to present

oral testimony or conduct oral cross-examination. The Ad-

ministrative Procedure Act provides in pertinent part that

A party is entitled to present his case or defense by

oral or documentary evidence, to submit rebuttal evi-

dence, and to conduct such cross-examination as may

be required for a full and true disclosure of the facts.

In rule making... an agency may, when a party will

not he prejudiced thereby, adopt procedures for the

submission of all or part of the evidence in written

form.

5 U.S.C.A. §556(d). The procedures used in setting the

national rate neither prejudiced the APGA, nor prevented

a full and true disclosure of the facts. On this appeal

petitioner APGA has failed to demonstrate that oral,

adjudicatory proce dures were necessary for a full and fair

disclosure of the facets. All private submissions and Com-

mission cost studies were on record either at the time of the

Notices in the case of Commission data or after the first

round of submissions, and petitioners had ample opportun-

ity for refutation, Evidence of a technical nature is well

suited for written dissection. Without conerete demonstra-

tion of how the Commission's reliance on written submittals

prejudiced the rights of the petitioners, we cannot say that

as a matter of law the FPC was prohibited from adopting

the procedures it did, or was required to conduct a full, oral

hearing.

As a second line of argument, the APGA contends that

even if the rulemaking procedure is statutorily correct, it

violates the due process rights of affected parties. Consti-

tutional due process “is flexible and calls for such proce-

dural protections as the particular situation demands.”

Morrissey v. Brewer, 408 US. 471, 481, 92 S.Ct. 2593, 33

L.Ed.2d 484 (1972). In FPC ratemaking we agree with the

D.C. Cireuit that:

Whatever procedure is utilized, a primary objective

is the aequisition of information which will enable the

Commission to carry out effectively the provisions of

the Natural Gas Act. The ability to choose with relative

freedom the procedure it will use to aequire relevant

information gives the Commission power to realisti-

eally tailor the proceedings to fit the issues before it,

the information it needs to illuminate those issues and

the manner of presentation which, in its judgment, will

bring before it the relevant information in the most

efficient manner.

City of Chicago v. FPPC, 458 F.2d 731, 743-44 (D.C.Cir.

1971), cert. denied, 405 U.S. 1074, 92 S.Ct. 1495, 31 L.led.2d

808 (1972). The procedures before us serve the purpose of

providing the Commission with essential information, while

protecting the procedural rights of concerned parties under

the circumstances. Private parties were afforded ample

opportunity to make their case and to challenge both inter-

nally and externally generated evidence of costs and con-

ditions [L076] which affected the caleulus of a national rate

for new gas. Were the Commission to have allowed all inter-

ested parties to submit oral testimony and conduct oral

cross-examination on an undertaking so massive and novel

as setting a national rate for new gas, the proceeding would

A-26

have taken vears, and the Commission’s power to effectively

regulate the industry would have been destroyed.

The Publie Service Commission for the State of New

York brings a more limited due process challenge, arguing

that insufficient notice was given that the Commission's

order would extend to renewal contracts which concern flow-

ing (“old”) gas. Under the circumstances, and in light of

the necessity to maintain flexible agency procedures, we

hold that New York received adequate notice of the en-

largement of scope. The Commission’s initial Notice of

Proposed Rulemaking issued on April 11, 1973, did not

indicate that old gas would be affected by the new national

rate, Prior to issuance of an F PC order, however, producer

groups raised the possibility of extending the order. New

York responded to the producer proposals, and, 42 days

after the issuance of Opinion No. 699, the FPC granted re-

hearing of that order, scheduling two days for oral argu-

ment, available to any party who wished to participate.

Following consideration of both written and oral argument

against Opinion No. 699, the FPC issued its final order on

rehearing, Opinion No. 699-H. Under these circumstances

the Public Service Commission's right to make its case

against extending the higher new rate to flowing gas was

not prejudiced. It had the opportunity to state its position

and refute positions to the contrary prior to the issuance

of Opinion No. 699, and thereafter New York had a fair

opportunity to argue against the FPC action before the

new rate system became final.

REVIEW OF SPECIFIC OBJECTIONS

TO NATIONAL RATE

Having concluded that the Commission was within its

authority in choosing a national rate structure to regulate

A-27

independent producers of natural gas, we now examine the

manner in which the FPC has applied its chosen meth-

odology to see that the essential elements of the various

orders are supported by substantial evidence or that they

otherwise withstand review. While the parties have at-

tacked many different components of the Commission’s

rate structure, we think only the following merit separate

treatment and extended comment. The other issues will be

discussed briefly in a miscellaneous portion of this section

of the opinion.

A. Application of New Rate to Renewal Contracts

[6] The Commission's decision to allow the new national

rate to be charged for natural gas sold pursuant to renewal

contracts replacing old contracts which had expired by their

own terms prior to January 1, 1973, where the sales under

the prior contracts were made pursuant to permanent cer-

tificates of public convenience and necessity of unlimited

duration, has been challenged as unjustified by some

producers and consumers. The producers, particularly

Superior Oil Company, assert that the requirement that

there be a newly executed contract is arbitrary. They rea-

son that since under the Conmission’s order the delivery

of natural gas must continue at the old rate under the cer-

tificate, even though there is no private contract, there is

no incentive for a pipeline to negotiate and the requirement

for a contract is, therefore, anticompetitive. Although the

producers can be relieved of this duty to continue deliveries

by successful prosecution of an abandonment proceeding,

such proceeding is costly both in terms of time, while the

lower rate is being received, and in terms of money to

prosecute the abandonment.

The consumer interests are represented on this issue by

Associated Gas Distributors, New York, and the American

A-28

Public Gas Association. These parties basically attack the

asserted rationale [1077] for the Commission decision as

being unsupportable in the record.

The Commission reasoned that application of the new,

higher rate to “old” gas as primary contracts expire will

generate added funds for greater exploration. The FPC

thus applied the rate functionally to “old” gas rather than

on a cost-related basis, hoping that a higher uniform rate

will help alleviate the current severe shortage. The FPC

believed that by requiring an old contract to be renegotiated

before the new rate is recoverable, the pipeline might be

able to negotiate for additional acreage dedication to inter-

state commerce, or exploration and development activity

on previously dedicated acreage or other concessions for

the price increase. The consumers argue that in this time

of an ever-increasing shortfall of supply the pipelines will

simply not be in the position to bargain for or gain any quid

pro quo, and, therefore, the Commission should have re-

quired some such concession from those producers who are

allowed the “windfall” rate increase on “old” gas.

The arguments on each side of this issue have some

validity, creating in their juxtaposition a contradiction

which buttresses this Court’s deferral to the reasoned ex-

pertise of the Commission. Our responsibility is not to

supplant the Commission's choice with one we might find

preferable, but simply to make sure that the Commission

has exercised its discretion after considering all pertinent

options. The FPC has reached a well-considered, expert

decision on this issue. The Comnussion found from evidence

in the record that a massive commitment of new funds is

necessary to alleviate the natural gas shortage and that

internally generated sums are a necessary source of such

funds. Additionally, it noted that by phasing out the vin-

A-29

taging practice and attending price variations, all con-

sumers would more equitably bear die burden of financing

added exploration. From these facts it reasoned that the

national rate structure should be functionally applied to

provide some of these funds, placing the burden not just

on “new” gas but also on flowing gas for which the primary

contract had expired. In so doing the Commission recog-

nized that natural gas is an exhaustible commodity and

expressed its belief that today’s consumers should share

the burden of finding replacement supplies for the supplies

which are being exhausted by the consumers.

Furthermore, the Commission does not consider the mat-

ter finally determined. It has expressly reserved for con-

sideration in the biennial review the question of whether

the pipelines are negotiating in good faith or trying to take

advantage of the producer's locked-in position, and whether

or not the additional funds generated by the application

of the new rate increase “the level of monies committed to

exploration and development programs and the volumes

of new gas supplies dedicated to interstate pipelines under

long-term contracts.” Opinion 699-H, Appendix pp. 564-65

and footnote 121. The Commission has thus remained flex-

ible and is prepared to adjust the national rate structure

as necessary. The Commission has struck a tentative bal-

ance between the consumer and the investor interests and

stated that it is prepared to reevaluate the equilibrium it

sought to achieve in the biennial review. Under such a

circumstance, no party has earried the heavy burden of

showing that the Commission’s balance is tilted so far in

either direction as to be unjust and unreasonable in its

consequence, We also consider the decision, although not

compelled by the evidence, to be supported by the sub-

stantial evidence of a shortage and the need for a massive

infusion of funds.

A-30

B. Trend Toward Elimination of Vintaging

[7] The practical result of allowing flowing or “old” gas

to be sold at the new national rate upon expiration or

renegotiation of preexisting contracts is that the former

“vintaging” of gas according to its period of discovery will

gradually disappear. The Commission is not bound by its

previous policies. As [1078] this Court and the Supreme

Court have noted on various occasions, the rate structures

which introduced or adjusted vintaging were experimental.

It is necessary without a doubt that agencies be permitted

latitude to evaluate old experiments and modify or abandon

them when their best judgment requires such a course of

action. The Commission’s reasons for permitting old gas to

be repriced at the new rate apply equally to the related

decision to abandon vintaging.

C. Commission's Productivity Projections

One of the most important and hard to predict variables

in the cost-based formula is productivity, the amount of

natural gas that will be added to nonassociated gas reserves

for every foot drilled resulting in some addition to those

reserves.

The Commission's decision as to predicted productivity

is attacked from both sides. Shell, Amoco and the United

Distribution Companies assert that the productivity esti-

mates ignored the only substantial evidence in the record

which showed a decreasing trend. American Public Gas

Association, on the other hand, contends that the produe-

tivity is overstated because the Commission did not use

the longest term data available, as had been its practice in

previous area rate cases. The parties do not really argue

that the ultimate productivity projections are not based on

substantial evidence, but rather assert that the Commis-

sion’s analysis of that evidence, and the inferences drawn

A-31

therefrom were incorrect. We find, however, that the Com-

mission's resolution of this admittedly difficult and uncer-

tain factual issue is supported by the record.

The record in this case presented two special problems

for the Commission in using historical figures to predict

future productivity in addition to those previously dis-

cussed: first, how to treat the historical rates in light of a

recent trend of decreasing productivity, and second, what

adjustment to make because of a Staff study which sug-

gested that some reported reserve additiens were under-

stated in the only available information source, American

Gas Association, American Petroleum Institute, and Cana-

dian Petroleum Institute, Reserves of Crude Oil, Natural

Gas Liquids, and Natural Gas in the United States and

Canada and United States Productive Capacity as of De-

cember 31, 1972, Vol. 27 (1973).

Because lower productivity means that the cost of drill-

ing must be spread over less natural gas, resulting in a

higher price per Mef, the producers urged the Commission

to accept the trend as valid and to predict an even lower

productivity for the future. In addition the producers

pcinted out that in this time of shortage more marginal

reserves, i. e., those with lower productivity, need to be

developed, and this will only occur if the productivity allow-

ance in the national rate justifies such a development, On

the other hand, the Associated Gas Distributors urged the

Commission to use only the data for 1952-1967, and to

ignore the decreasing productivity trend from 1968 as being

based on unreliable reserve data.

[8] Faced with these conflicting positions, the Commis-

sion made a choice of what evidence to use in predicting

productivity over the effective period of its rate order. The

FPC adopted a middle ground computing the productivity

A-32

for the “high” end of its range of reasonable rates from

the most recent seven years (1966-1972) and computing the

“low” end from the most recent ten years (1963-1972),

making adjustment to the final rate range for the Staff-

found understatement of nonassociated reserves. This

choice of evidence is itself subject to review by this Court

for evidentiary support. Southern Louisiana Area Rate

Cases, supra at 425 n. 42.

The Commission recognized that the trend of decreasing

productivity resulted from the interaction of two factors:

drilling footages had dramatically increased in recent years

as producers redoubled the search for nonassociated natural

gas in the face of the national [1079] shortage, but reserve

additions had steadily declined. Tiere is no dispute over the

existence of substantial evidence of the facts which demon-

strate these two factors. The Commission analyzed these

trends to project tle likelihood of their continuance.

The FPC reasoned that the steady decline in reserve ad-

ditions data was adjusted downward for significant net

negative revisions to existing nonassociated gas reserves,

as estimates for older reservoirs were updated to reflect

continuing production experience. There is no way that the

reservoir which is negatively adjusted can he isolated by

year of discovery so that productivity for that year could

be properly adjusted. Instead the productivity for the year

in which the discrepancy is discovered is affected. The sec-

ond factor which the Commission considered important in

correctly understanding the reserve addition data was the

low level of new field and new reservoir discoveries. The

FPC believed this to be abnormally low and a result of

decreased leasing in the offshore federal domain in the late

1960’s. It anticipated an increase in such discoveries would

result from an increase in such leasing.

A-33

—

The Commission acknowledged that it was impossible to

isolate the age of the reservoirs which accounted for the

negative revisions, but expressed its belief, based on the

fact that the revisions were obtained from “continuing

production experience,” that at least a substantial portion

of the large negative revisions related to older reservoirs.

The FPC considered such revisions nonrecurring. Con-

sidering all of these facts and the inferences it drew from

them, the Commission concluded that nonassociated gas

reserve additions had been abnormally low in the recent

past and anticipated an increase in the near future.

(9] The Commission recognized that drilling footages

had increased and could be anticipated to continue imeveas-

ing as the search for natural gas broadened, In fact, one

of the primary goals of the FPC in formulating the national

rate in this case was to stimulate exploration and develop-

ment of new reserves. The Commission concluded, however,

that the negative effect on productivity of this increased

drilling was likely to be offset by the increased reserve

additions it anticipated as developing. Because of this inter-

action, the Commission considered the productivity trend

as unrepresentative of projected productivity and chose

instead to rely on averages of past data to compensate for

the inaccuracy of the reserve reporting system and for the

instability of short range trends as demonstrated by various

historical abrupt changes. Using 1966-1972 data, the Com-

mission made a “high” estimate of 485 Mef per foot, and

using the 1963-1972 data, the Commission made a “low”

estimate of 559 Mef per foot. Produetivity for 1972 had

been 286 Mef per foot. The Commission apparently gave

consideration to all factors involved in the productivity

determination and arrived at an accommodation of the

competing theories. That accommodation, although not the

A-34

only one which could be made, is sufficiently supported by

the record to withstand judicial review.

D. Move to Discounted Cash Flow Model in 699-I

[10] The FPC’s choice of the Discounted Cash Flow

(DCF) methodology in Opinion 699-H is the subject of

attack from all quarters. This accounting process focuses

on cash flow over a set period of time rather than on net

income in any one year. The underlying principle is that

money has a time value. An amount received a year from

now, for example, is worth less than an equal amount

currently in hand. This is the principle wpon which bonds

bearing below-market rates of interest are discounted.

Similarly, an expenditure made in year 1 is more costly

than an equal expenditure made in year 2.

Discourted Cash Flow accounting focuses on two factors:

net cash outflow and net cash inflow. In the FPC model all

calculations are made by reference to the first vear of pro-

duction. Net investments (cash outflow) made during the

four years prior to production of natural [1080] gas are

increased at a 15 percent compounded annual rate to give a

value as of the first vear of production. This 15 pereent

annual rate reflects the permissible rate of return allowed

by the FPC.

In the second stage of the model, the FPC projects

future net cash inflows (future gross revenues less annual

expenses) for each year of gas production. The model

apparently assumes that operations will terminate after 17

years of gas production, These yearly amounts are dis-

counted by a 15 percent annual rate, again a reflection of

allowable return on investment. (Future net cash inflows

are the equivalent of installment payments on indebtedness,

If such payments are discounted by a specifie percentage,

A-35

that discount represents the interest which the lender re-

ceives as a return on his investment).

The final calculation of the FPC model is to simply say

that future cash inflows, discounted at a 15 percent rate to

allow a 15 percent return, must equal previous cash outflow

in the form of start-up costs.

The producers attack the injustice of this model in the

context of its inclusion of federal income tax eredits and

exclusion of tax liabilities in exeess of those credits. In

addition these petitioners variously challenge the time lag

and future cash flow assumptions and the failure to provide

for cost increases. One consumer group, the American

Public Gas Association, questions assumptions about the

rate of production and depletion, and use of trended drilling

costs. The most serious challenge which the consumer

groups bring is their assertion that this new methodology

was adopted in midstream, without a sufficient evidentiary

foundation, and that the adoption of DCF resulted in an

unreasonable increase in the rate for natural gas from 42¢

per Mef to 50¢. Without delving into the complexities of

an esoteric costing methodology which counsel could

searcely describe in their briefs or at oral argument, we

need only note that a reviewing court would go far afield in

striking down an analytical model adopted by the Commis-

sion. As the Supreme Court long ago observed,

Under the statutory standard of “just and reasonable”

it is the result reached not the method employed which

is controlling [citations omitted]. It is not theory but

the impact of the rate order which counts. If the total

effect of the rate order cannot be said to be unjust and

unreasonable, judicial inquiry under the Act is at an

end. The fact that the method employed to reach that

result may contain infirmities is not then important.

A-36

FPC v. Hope Natural Gas Co., 320 U.S. 591, 602, 64 S.Ct.

281, 287, 88 L.Ed. 333 (1944). To attack the Discounted Cash

Flow methodology, petitioners must therefore demonstrate

that it results in an unjust and unreasonable end result.

Petitioners failed to sustain this weighty burden of proof,

either specifically with respect to the DCF methodology, or

with respect to the F PC's rate structure in general.

EK. Federal Income Tax Issue

[11] The producers strongly urge that the Commission

committed reversible error when it excluded a federal in-

come tax component from the national rate for natural

gas. Rather than calculate an average rate of tax which

would be uniformly factored into the cost for natural gas,

the FPC instead set a rate exclusive of federal income tax

and announced that when producers can demonstrate dur-

ing an extraordinary relief proceeding that their natural

gas operations resulted in actual income tax liability,

higher rates will be permitted to reflect that tax.

One argument made against the Commission's refusal

to augment the national rate by an average tax figure is

that the Commission thereby acted inconsistently because

it paradoxically reduced the rate by an average tax credit

figure. There is no support in the statute or in precedent

for the assertion that the Commission’s treatment of fed-

eral taxes as a whole renders the area ratemaking concept

deficient, illogical, or unfair.

[1081]

A second argument is made against the Discounted Cash

Flow model's treatment of income tax. The model reduces

recoverable start-up costs by the amount of tax credits

generated by such costs and factors in automatic recovery

of income taxes during the period of production only to

A-37

the extent that tax liability offsets previous tax credits.

Thus the model assumes that income tax liability will not

exceed income tax credits. It toes not allow a return on

initial investment which is sheltered by tax credits. Where

tax liability exceeds credits, producers must petition for

special relief. The producers’ assertion that the FPC is

taking a “double dip” against producer costs is not well

taken. While average federal tax deductions are included

to reduce start-up costs, an equal amount of tax liability

is added to increase the cash flow which is later generated

by gas rates during production, and individual tax liability

in excess of this amount is recoverable at the time when

such liability accrues through the special relief process.

There is nothing so unjust or unreasonable about this

treatment of tax costs as to require judicial intervention.

The Commission's policy choice of excluding an average

tax liability figure in excess of tax credits was based o>

findings of fact, lending weight to our conclusion that the

net effect of the DCF treatment of federal income tax is

not unjust or unfair. Evidence demonstrated that the tax

liability of producers varied widely, thus making an aver-

age extremely imprecise. The Commission also took note

of the complexity of federal income tax provisions for gas

producers, the ability of producers in some circumstances

to indefinitely postpone tax liability, and the impending

reduction of depletion allowances, all good reasons for

eschewing a simple tax component which would be cemented

into ratemaking for a long time to come. There appears

to be no danger that a producer who actually pays taxes

will not be able to recover that cost.

Producers also contend that the treatment of tax credits

in the DCF model cheats them of a return on investment

which is offset by tax deductions. By this argument pro-

A-38

dueers ask us to substitute an alternative investment base

for the one which the Commission seleeted. That would

amount to the imposition of our discretionary choice upon

an expert agency, which is not permitted.

F. Rate of Return

{12] The selection of a rate of return is overtly a

factual determination and has been treated as such during

the course of this litigation, but the Commission made an

implicit policy choice which controls the nature of the rele-

vant factual issues at hand. The Commission could prob-

ably have sought a rate of return which merely avoided

charges of confiscation. But the FPC did more, seeking

as it did a rate of return which at a minimum is competi-

tive with other industries, and moreover encourages ex-

ploration. One petitioner, United Distribution Companies,

challenged the 15 percent rate of return as being inade-

quate for these purposes, and asserts that the factual data

supporting the decision to fix a 15 percent rate of return

was not considered during the agency proceeding.

The Commission is to be upheld regardless of whether

one views the rate of return as a factual determination

which is subject to the substantial evidence standard of

review, or as a parameter of the DCF model which is en-

titled to the less severe standard for reviewing a disere-

tionary selection of policy and methodology. The record

reveals that the Commission carefully evaluated average

rates of return on capital invested in other industries and

concluded that a zone of reasonableness spanned from 12

percent to 15 percent. The selection of the highest rate of

return within the zone was based on the desire to provide

the extra incentive which the Commission felt is needed

to encourage increased exploration and development. We

A-39

find no ground for either reversing the policy of setting a

rate which attracts capital into natural gas production, or

setting aside the factual base that supports the choice of

a 15 percent rate of return.

G. Lease Acquisition Costs

[13] Shell Oil and allied producers allege that the new

national rate for natural gas understates Lease Acquisi-

tion Costs by approximately 25¢ per Mef. They recite

factual data which indicates a dramatic increase in

bonuses paid by producers to the federal government in

recent vears for Outer Continental Shelf gas leases. Their

evidence includes scattered federal lease information per-

taining to acquisition costs from 1972 through 1974, and

actual successful well cost data for 1973. The 1973 total,

$2 billion dollars, was not available until February of 1975,

three months after the issuance of Opinion 699-H. By con-

trast, the Commission based its lease acquisition cost

estimates on six-year (1967-1972) cost averages and five-

year (1968-1972) “Trended Data.”

The Commission’s projections are based on substantial

evidence and cannot be reversed at this stage. Their evalu-

ation is necessarily constrained by the time lag in com-

piling data of this kind. The recent developments to which

Shell and others point is not so compelling as to require

that 18 year projections be based on extraordinary recent

developments. While the Commission is surely obligated

to monitor these developments so that future adjustments

provide for just and reasonable recoupment of lease aequi-

sition costs, the Commission exercised proper discretion

in basing its determination on long range rather than

extraordinary and incomplete recent data.

A-40

H. Net Liquid Credit

[14] Net Liquid Credit is a cost equation component

of relatively little import. Gas producers are able to capture

a small amount of liquefiable petrocarbons as by-products

of natural gas production. These petrocarbons are sold at

a profit and are factored in as a credit which helps offset

costs that are allocated through the rate charged to con-

sumers of natural gas (the present credit amounts to 3.89¢

per Mcf). In setting the amount of the credit the Commis-

sion took notice of the fact that prices paid for this petro-

leum condensate are increasing, causing the credit to be

understated. There is also evidence, however, that the

amount of condensate produced is declining. The Com-

mission in its opinion indicates that it is continuing the

evaluation of these trends. While there is some merit in

the charge that the evidence supporting the level set by

the Commission is thin, it is not so insubstantial to war-

rant reversal of the Commission’s evaluation of and re-

sponse to these trends, especially in light of the implied

promise to adjust the credit as further facts unfold. Cer-

tainly the magnitude of the issue is not sufficient to render

the FPC order unjust and unreasonable.

I. Refund, Work-off and Contingent Escalation Pro-

visions

[15] Under previous area rate agreements the FPC

determined that certain producers were obligated to refund

overcharges to pipelines. The producers were allowed, how-

ever, to “work-off” the obligation by receiving a 1¢ credit

for each Mef of new gas dedicated to interstate commerce

in the affected area, as long as half of such gas is sold to

the pipeline which was previously overcharged. See, e. q.,

Permian Basin Area Rate Proceedings, 50 F.P.C. 390

A-4l1

(1973); Texas Gulf Coast Area Rate Proceeding, 45 F.P.C.

674 (1971). In addition, the Commission provided for rate

escalations contingent on the dedication of additional flow-

ing gas to the interstate market by a given date. In Opinion

Nos. 699 and 699-IIl the FPC provided that natural gas

sold at the new national rate could not be used to discharge

refund obligations or to trigger contingent escalations. Pro-

ducers argue before this Court that this constitutes an im-

proper retroactive modification of prior rate opinions. We

disagree. By its orders which are here at issue, the FPC

has established a new rate system for gas dedicated to

interstate commerce after January 1, 1973, in addition to

gas from certain other sources. The new national rate is

the product of an independent determination of incentives,

and, as it is in so many other regards, the new rate struc-

ture is not tied to previous determinations. Replacing one

incentive structure with another or, viewed in another light,

providing a new alternative rate system, is an exercise of

Commission discretion which does not amount to retro-

active rate regulation. See Moss v. F PC, 164 U.S.App.

D.C, 1, 502 F.2d 461 (1974).

J. Limited Term and Emergency Sales Procedures

[16] In Opinion No. 699 the Commission modified its

previous limited term and emergency sales procedures, Cf.

18 C.FLR. §§ 2.70, 157.29 (1974). The Commission provided

that sales from the offshore federal domain made under both

the limited term and the emergency sales procedures should

not exeeed the new national rate, and it limited the term of

such sales to a single 60-day sale from a particular well or

group of wells. The FPC reasoned that “the present gas

shortage requires long-term solutions, not stop gap meas-

ures.” It based its decision to limit these short-term proce-

A-42

dures on substantial evidence showing that an inordinate

amount of new deliveries to the interstate market for 1971

to 1973 are traceable to emergency and limited-term sales.

The FPC action is attacked on a number of fronts. The

producers group contends that limited term and emergency

sales should be allowed to exceed the national rate. A num-

ber of pipeline companies argued that the Commission erred

in restricting sales from a well or a group of wells to a

single 60-day period, and they assert that the Commission

failed to establish sufficiently clear guidelines for the pipe-

lines’ recovery of their costs for emergeney purchases.

As to the latter issue, the Commission has in fact stated

the standard for acceptable cost recovery :

If a pipeline seeks to purchase gas in interstate com-

merce for only a short period of time at a price in ex-

cess of the national rate, there must be credible

evidence demonstrating that the gas is to be purchased

at the lowest price for which the pipeline could have

obtained the gas, and that such gas supply is not

available for a long-term dedication at the present

national rate.

Opinion No, 699-F. This standard is expanded by the state-

ment in Opinion No, 699-B that pipelines should “be entitled

to pay a rate for emergency purchases which a reasonably

prudent pipeline purchaser would pay for gas under the

same or similar circumstances.”

We have approved the Commission's objective of achiev-

ing a monolithic national rate for natural gas. Its limitation

of short-term emergency sales to 60 days, and its restriction

of the price at which jurisdictional sales may be transacted

are acceptable means to that end. By its action the FPC has

protected the integrity of the new national rate and has

A-48

promoted long-term relationships between producers and

pipelines. Its decision to restrain allowable short-term

transactions was based on substantial evidence that an

abundance of these transactions adversely affects long-term

national ratemaking, and is therefore not reversible.

K. Other Noncost Considerations

(17, 18] Various petitioners argue that the Commission

erred in failing to consider nonecost factors which are

created by market forces. Specifically, the producers base

their argument for higher rates on a comparison between

the FPC’s new rate for natural gas and higher price of

both oil and natural gas in the unregulated intrastate

market. They argue that the national rate for regulated

gas should equal the “commodity value” of gas determined

by comparison with substitutable fuels such as oil. In

essence, these petitioners would have us set the price of

natural gas at the rate that the market would bear, The

commodity price of gas would most likely be set by the

prevailing price of oil and the cross-elasticity of demand

between gas and oil. To accept this free market “commodity

b]

value” would be to eschew the congressionally mandated

responsibility of rate regulation which is devised to reach

a “just and reasonable” rate. Fixing a “just and reasonable”

rate for a product sold in an inherently uncompetitive

market requires more than mere subservience to national

and international market forces. Just as the Natural Gas

Act does not limit the Commission’s determination to cost-

related ratemaking, neither is the Commission obliged to

incorporate specific noneost factors into its calculus.

As another way of phrasing their argument that the

“commodity value” of natural gas should determine the

national rate, a number of producers argue that the FPC

A-44

was erroneous in its use of cost-based ratemaking. But the

Supreme Court has recently concluded upon a search for

congressional intent that “the Commission lacks the au-

thority to place exclusive reliance on market prices,” PPC v.

Texaco, Inc., 417 U.S. 380, 400, 94 S.Ct. 2315, 2327, 41 L.Ed.

2d 141 (1973). The Commission’s long and often judicially

approved practice of basing rates on cost carries a sub-

stantial presumption of validity which places a heavy bur-

den on those who would refute it. As noted above, the

overall rate structure must be challenged on the basis of

improper net effect. PPC v. Hope Natural Gas Co., 320 U.S.

591, 602, 64 S.Ct. 281, 88 L.Ed. 333 (1944). The cost-hased

national rate on review before us is experimental. It repre-

sents a dramatic increase in the allowable price for inter-

state gas. It is premature to decide, as the producers

would have us decide, that this experimental price increase

— the effect of which cannot vet be measured — is not

enough.

The statutory standard for review of FPC policy re-

quires an examination of the end result of a rate structure.

Petitioners have not met their burden of demonstrating

that the natural gas rate must reflect noneost, market

conditions in order to be just and reasonable, 7. e., they

have not shown that the FPC policy of basing the natural

gas rate on cost rather than on market forces produces an

end result which is harmful to the public interest.

CONCLUSION

Having carefully reviewed all of the various arguments

against the validity of the Commission orders under review,

we are constrained to uphold the Commission’s action.

A-45

APPENDIX B

OPINION AND ORDER OF THE UNITED STATES COURT OF

APPEALS FOR THE FIFTH CIRCUIT DENYING CERTAIN

PETITIONS FOR REHEARING IN SHELL OIL COMPANY v.

FEDERAL POWER COMMISSION (NATIONAL RATE CASES

FOR NEW GAS) 525 F.2d 1063, DECIDED JANUARY 14,

1976.

ne

SHELL OIL COMPANY et al., Petitioners,

v.

FEDERAL POWER COMMISSION, Respondent.

No. 74-3330.

United States Court of Appeals,

Fifth Cireuit.

Jan. 14, 1976.

Petitions for Review of Orders of the Federal Power

Commission.

ON PETITIONS FOR REHEARING

(Opinion Oct, 14, 1975, 5 Cir., 520 F.2d 1061)

Before BELL, CLARK and RONEY, Cireuit Judges.

PER CURIAM:

In its petition for rehearing, Rodman Corporation and

others request us to reconsider our decision “to provide

that the FPC (i) include a component for federal incomes

taxes liability in the nationwide rate, (ii) eliminate the

deduction of federal income tax credits from the nation-

wide average rate, or (ili) make ‘erystal clear’ that a de

novo review of federal income tax in the current biennial

review proceeding in FPC Docket No, RM 75—14 is permis-

sible.”

We agree that our decision should in no way be construed

to foreclose a de novo review of federal income tax in the

current biennial review proceeding in FPC Docket No, RM

75—14.

It is ordered that the petitions for rehearing filed in the

above entitled and numbered cause be and the same are

hereby denied.

B-1

Pi -

APPENDIX C

OPINION NO. 699 OF THE FEDERAL POWER COMMISSION,

OPINION AND ORDER PRESCRIBING UNIFORM NATIONAL

RATE FOR SALES OF NATURAL GAS PRODUCED FROM WELLS

COMMENCED ON OR AFTER JANUARY 1, 1973, AND NEW

DEDICATIONS OF NATURAL GAS TO INTERSTATE COMMERCE

ON OR AFTER JANUARY 1, 1973 (ISSUED JUNE 21, 1974).

[2632]

[2632] °

UNITED STATES OF AMERICA

FEDERAL POWER COMMISSION

OPINION NO. 699

Just And Reasonable National Rates For ) Docket No.

Sales Of Natural Gas From Wells Com-) R-389-B

menced On Or After January 1, 1973 )

OPINION AND ORDER PRESCRIBING

UNIFORM NATIONAL RATE FOR SALES OF

NATURAL GAS PRODUCED FROM WELLS COM-

MENCED ON OR AFTER JANUARY 1, 1973,

AND NEW DEDICATIONS OF NATURAL GAS

TO INTERSTATE COMMERCE ON OR AFTER

JANUARY 1, 1973

Issued: June 21, 1974

*Transcript Page Number

C-1

[2633]

[2633]

UNITED STATES OF AMERICA

FEDERAL POWER COMMISSION

[18 C.F.R. Parts 2 ($§2.56, 2.70), 154, 157 (§157.29)]

Before Commissioners: John N. Nassikas, Chairman;

Albert B. Brooke, Jr., Rush

Moody, Jr., William L.

Springer, and Don S. Smith.

Just And Reasonable National Rate For )

Sales Of Natural Gas From Wells Com-)

menced On Or After January 1, 1973 ) Docket No.

And New Dedication of Natural Gas ) R-389-B

To Interstate Commerce On Or After )

January 1, 1973 )

OPINION NO. 699

OPINION AND ORDER PRESCRIBING

UNIFORM NATIONAL RATE FOR SALES OF

NATURAL GAS PRODUCED FROM WELLS COM-

MENCED ON OR AFTER JANUARY 1, 1973, AND

NEW DEDICATIONS OF NATURAL GAS TO

INTERSTATE COMMERCE ON OR AFTER

JANUARY i, 1973

(Issued June 21, 1974)

NASSIKAS, Chairman:

In this proceeding, we establish a single uniform na-

tional base rate of 42.0 cents per Mcf for following

classes of jurisdictional sales of natural gas: (1) sales

C-2

[2634]

made from wells commenced on or after January 1, 1973,

(2) sales made pursuant to contracts executed on or

after January 1, 1973, for the sale of natural gas in in-

terstate commerce where such gas has not previously been

sold in interstate commerce except pursuant to the pro-

visions of 18 C.F.R. §§2.68, 2.70, 157.22 or 157.29, or

(3) sales made pursuant to contracts executed on or after

January 1, 1973, where the sales were formerly made pur-

suant to permanent certificates of unlimited duration un-

der contracts which expired by their own terms on or

after January 1, 1973. This rate is found to be just and

reasonable rate and is

[2634]

subject to adjustment for Btu content, State or Federal

production, severance, or similar taxes, annual escala-

tions of 1.0 cent per Mcf, and gathering allowances, which

are also found to be just and reasonable. The rate is ap-

plicable to oil-well (casinghead) gas as well as gas-well

gas, and shall remain in effect until modified by the Com-

mission.

On April 11, 1973, the Commission issued a notice of

proposed rulemaking in Docket No. R-389-B,’ pursuant

to the Administrative Procedure Act, 5 U.S.C. §551,

et seq. (1970) (APA),* and Sections 4, 5, 7, 8, 14, 15,

and 16 of the Natural Gas Act, 15 U.S.C. §717, et seq.

(1970),* and proposed to issue rules establishing the just

1. 38 Fed. Reg. 10014 (1973).

2. 60 Stat. 237, 918, 993 (1946); 61 Stat. 37, 201 (1947); 62

Stat. 99 (1948); 80 Stat. 250 (1966).

3. 52 Stat. 822, 823, 824, 825, 829, 830 (1938); 56 Stat. 83, 34

(1984); 61 Stat. 459 (1947); 76 Stat. 72 (1962); 15 U.S.C. §$717c,

717d, 717f, 717g, 717m, 717n, 7170 (1970).

C-3

[2634]

and reasonable rates for, and otherwise regulating, juris-

dictional sales of natural gas on a nationwide basis. The

single uniform just and reasonable rate to be determined

by a final order in Docket No. R-389-B would apply to

all jurisdictional sales of natural gas which is produced

from wells commenced on or after January 1, 1973, ex-

cept for those sales certificated under Order No. 431 or

Order No. 491,* those sales certificated under Order

[2635]

No. 455,’ or sales made by small producers under the

terms of Order No. 428.° Such notice made all large pro-

ducers respondents to the rulemaking proceeding, pro-

vided for the submission of written comments (submitted

4. 18 C.F.R. §2.70; Policy With Respect To Establishment Of

Measures To Be Taken For The Protection Of As Reliable And

Adequate Service As Present Natural Gas Supplies And Capacities

Will Permit, Docket No. R-418, Order No. 431, 45 F.P.C. 570

(1971), as amended by Order No. 431-A, 48 F.P.C. 197 (1972).

See also, Policy With Respect To Establishment Oj Measures To

Be Taken For The Protection Of Reliable And Adequate Service For

The 1973-1974 Winter Heating Season, Docket No. KM74-3, Order

No. 491, 50 F.P.C. (September 4, 1973), as amended by Order

No. 491-A, 50 F.P.C. (September 25, 1973), Order No. 491-B,

50 F.P.C. (November 2, 1973), Order No. 491-C, 50 F.P.C.

(November 21, 1973). Stay of Order Nos. 491 and 491-B entered by

the U. S. Court of Appeals (D.C. Cir.) was vacated in FPC v. Con-

sumer Federation of America, American Public Gas Association, Amer-

ican Public Power Association, National League of Cities—U. S. Con-

ference of Mayors, 414 U.S. 1117 (1973).

5. 18 C.F.R. §2.75; Optional Procedure For Certificating New

Producer Sales Of Natural Gas, Docket No. 441, Order No. 455, 48

F.P.C. 218 (1972), as amended by Order No. 455-A, 48 F.P.C. 477

(1972), appeal pending sub nom. John E. Moss, et al. v. F.P.C., Nos.

72-1837, et al. (D.C. Cir. September 11, 1972.)

6. Exemption Of Small Producers From Regulation, 45 F.P.C. 454

(1971), as amended 45 F.P.C. 548 (1971), reh. denied, 46 F.P.C. 47

(1971), reversed, Texaco Inc., et al. v. F.P.C., 153 U.S. App. D.C.

195, 474 F.2d 416 (1972), vacated and remanded, 42 U.S.L.W. 4867

(U.S. June 10, 1974).

C-4

ee ee

on

[2636]

under oath) from all interested parties and the named re-

spondents, and was accompanied by a Staff study on the

estimated nationwide cost of finding and producing new

nonassociated natural gas supplies.

The Commission in that notice did not propose any

specific rates, terms, or condition in the notice, but stated

that it would amend Section 2.56 of the Rules of Prac-

tice and Procedure, General Policy Statements and In-

terpretations (18 C.F.R. § 2.56) in accordance with its

determinations based upon information contained in the

responses submitted by the various parties and the Staff

study accompanying the notice of proposed rulemaking.

The original notice of rulemaking was supplemented

on March 21, 1974, when a “Notice Of Issuance Of Re-

vised Staff Nationwide Cost Study And Staff Study Of

American Gas Association Reserve Additions” was is-

sued.’ In the March 21, 1974, notice, the Staff cost esti-

mates which accompanied the original notice of rule-

making in this proceeding were updated to reflect 1972

drilling cost

[2636]

data reported by the Joint Association Survey (1972

JAS) and nonassociated natural gas reserve additions ior

1972 as reported by the American Gas Association

(AGA). The Staff cost studies accompanying the April

11, 1973, notice were revised in the March 21, 1974,

notice to reflect a 10.5 year investment life for updated

test periods of seven years (1966-1972) and the average

of the 11, 16, and 26 year average productivities (1966-

1972; 1957-1972; 1947-1972). Additional cost studies

7. 39 Fed. Reg. 11310 (1974).

C-5

[2636]

for a ten-year test period (1963-1972) and a four-year

test period (1969-1972) were also presented in Revised

Appendix B. Appendix B-1 to the associated natural gas

reserve additions for selected leases in the Southern

Louisiana Offshore Federal Domain. The results of this

study indicated that AGA reserve additions for 1971 and

1972 might be understated by approximately 1.7 trillion

cubic feet (Tcf). In addition to comments directed to the

two Staff cost studies, the Commission also requested

comments upon a number of issues, viz., the appropriate

method for determining the rate of return, the utilization

of full cost accounting, the utilization and reliability of

the more recent cost data, the utilization of trending to

determine new gas costs and the time series which would

form the basis for the statistical trending, whether an ad-

ditional allowance should be provided for deeper drilling

and water depths, and what non-cost factors are appro-

priate for consideration in the costing of new gas sup-

plies and how such factors can be quantified.

Further, by order of April 12, 1974,° the Commission

extended the time for the filing of comments in response

to the March 21, 1974, notice and required that certain

issues presented by the United Distribution Companies

and their consultant, Mr. William J. Ogden, be presented

at a conference to be held in this proceeding on April 16,

1974. This conference had been requested by the Ameri-

can Gas Association in an effort to resolve the disparity

between nonassociated natural gas reserve additions for

1971 and 1972 as reported by

[2637]

the American Gas Association and the reserve additions

8. 39 Fed. Reg. 13976 (1974).

C-6

Neen nn a

{2638}

found by our Staff to be related to some 31 leases in the

offshore Southern Louisiana area.”

In summary, the continuing and deepening natural gas

shortage’ and critical shortages of other energy sources

which have resulted in a national energy emergency re-

quires that this Commission take all prudent steps to in-

sure that the rates allowed for natural gas sold in inter-

state commerce are adequate to bring forth the requisite

supplies to fulfill reasonable demand while protecting the

“consumers against exploitation at the hands of natural-

gas companies.”'' Thus, the Commission faces a formid-

able task: establishing rates high enough to provide the

economic incentive for the unprecedented task of finding

enormous volumes of new gas supplies but not so high

that the natural gas consumer is exploited during a time

of shortage.

[2638]

To that end, we have determined that a single uniform

national rate promulgated in this rulemaking proceeding

will enable us to establish just and reasonable rates for

9. Notice of this conference was published in the Federal Register

on April 9, 1974, 39 Fed. Reg. 13199 and a revised notice indicating

that the meeting would be of record was published in the Federal

Register on April 9, 1974. 39 Fed. Reg. 13199.

The letter from the American Gas Association requesting the meet-

ing was made a part of the public record and the transcript of the

meeting (1 Tr. 5).

10. The natural gas shortage has been judicially recognized. £.g.,

F.P.C. v. Louisiana Power & Light Co., 406 U.S. 621 (1972); Placid

Oil Company, et al. v. F.P.C., 483 F.2d 880 (Sth Cir. 1973), affirmed

sub nom. Mobil Oil Corporation, et al. v. F.P.C., 42 US.L.W. 4842

(U.S. June 10, 1974). Shell Oil Company, et al. v. F.P.C., 484 F.2d

469 (Sth Cir. 1973), cert. denied sub nom. Mobil Oil Corp. v. F.P.C.,

Nos. 73-438, et al. (June 17, 1974).

11. Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 685 (1954).

C-7

[2638]

natural gas sold in interstate commerce without the in-

herent delays and stale records which have accompanied

the traditional adjudicatory method of regulating producer

rates.’ The prescription of a uniform national rate for

all areas will avoid essentially duplicative procedures and

evidence to prescribe just and reasonable rates for the

various natural gas producing areas of the Nation, and

will enable the Commission to utilize its manpower and re-

sources for more effective administration of the Natural

Gas Act. By the use of the Commission’s rulemaking

powers in this and future proceedings, we and future Com-

missions will be able to prescribe just and reasonable

rates on a biennial basis using the most recent evidence

and bringing expertise gained in related proceedings io

bear upon this problem of assuring an adequate supply

of natural gas for the Nation.’*

[2639]

I.

PROCEDURAL ISSUES

Most of the parties responding to the notice of the pro-

posed rulemaking commented favorably upon the Com-

mission’s attempt to arrive at an expeditious determination

of a single uniform national rate for all jurisdictional

sales made from wells commenced on or after January 1,

12. The first area rate proceeding, Permian Basin Area Rate Pro-

ceeding, et al., 34 F.P.C. 159 (1965), consumed five years before the

Commission, and it was an additional three years before the Commis-

sion’s decision was affirmed by the Supreme Court in the Permian

Basin Area Rate Cases, 390 U.S. 747 (1968).

13. Cf. City of Chicago v. FPC, 147 U.S. App. D.C. 312, 458 F.

2d 731 (D.C. Cir. 1971), cert. denied, 405.U.S. 1074 (1972); Sun

Ou Co. v. FPC, 256 F.2d 233, 240-241 (Sth Cir.), cert. denied, 358

US. 872 (1958).

C-8

Soetanen es

[2639]

1973. However, a number of parties expressed reserva-

tions concerning the Commission’s decision to establish

a uniform rate for all producing areas in view of the dif-

fering conditions of the Rocky Mour «ain Area, the Ap-

palachian-lllinois Basin Area, and the Deep Anadarko

Basin.**

The Commission has determised that ‘the single uni-

form national rate established herein should be applicable

to the lower 48 states (onshore and offshore). The cur-

rent natural gas shortage requires that the Commission

act expeditiously to establish a generally applicable rate

for all producing areas before areas that may present

special cost circumstances are accorded additional con-

sideration to determine if different rates should be estab-

lished in those areas to compensate for local peculiarities.

The fact that the rate determined herein may not be as

advantageous to some producers as others is not control-

ling. The Supreme Court held in the Permian Basin Area

Rate Cases, 390 U.S. 747 (1968), that the use of aver-

age nationwide costs to establish an area rate was a per-

missible means of rate regulation under the Constitution,

390 U.S. 747 at 768-770, and the Natural Gas Act, 390

U.S. 747 at 774-777. The cost of “new gas” in each of

the area rate cases (with the single exception of the Ap-

palachian-Illinois Basin Proceeding) was determined from

nationwide data and then adjusted for local production

taxes and gathering practices. The end result of the area

rate experiment was in effect a uniform national rate for

new gas by areas based upon the evidentiary record in

14. See for example the comments of Cabot Corporation, The

Public Utilities Commission of the State of Colorado, Colorado Inter-

state Gas Company, Columbia Gas System Service Corporation, Equi-

table Gas Company, The GHK Company, Public Service Commission

for the State of New York, and Public Service Company of Colorado.

C-9

[2639]

those individual area rate proceedings. During the course

of the various area rate cases,

[2640]

the data base upon which the Commission relied for its

determination of rates was updated to reflect the recent

data which was considered to be more representative of

current cost trends than the older data relied upon in the

first Permian Proceeding. Thus, the various rates are not

absolutely identical. In this proceeding the average nation-

wide cost of “new gas” will be applied to all areas (on-

shore and offshore) subject to annual escalations and ad-

justments for production taxes, Btu content, and gather-

ing allowances which are set forth in the rate structure.

Furthermore, producers may petition the Commission for

special relief from the national rate under the circum-

stances and limitations hereinafter set forth. The Com-

mission has concluded that the question of whether special

area rates should be establisi.ed for the Appalachian-Ill-

inois Basin Area, the Rocky Mountain Area, and the

Deep Anadarko Basin will be deferred pending further

consideration of that matter.

Two parties responding to the notice of proposed rule-

making (Public Service Commission for the State of New

York and Dr. Keith Brown) raised the issue of whether

certain gas producing areas have a “locational value” due

to their proximity to major natural gas consuming areas.

This question is pertinent to the prices established for the

areas outside of the major producing areas of the South-

ern and Southwestern states, i.e., the Appalachian-Illinois

Basin Area and the Rocky Mountain Area. As for the

major producing areas of the Southern and Southwestern

states, it should be noted that the natural gas flowing into

C-10

wie Rem APS set er nee

et

[2641]

the interstate markets from those states flows to gas con-

suming markets throughout the United States, and it is

not possible to determine a single “locational value” for

these areas which are connected to pipelines serving mar-

kets dispersed throughout the United States. Moreover,

any attempt to assign a number of “locational values” to

any given area would hopelessly and needlessly complicate

the rate structure established herein.

Furthermore, the Commission is aware of the fact that

considerable inequity and economic dislocation could re-

sult from a fundamental restructuring of the

]2641]

basic area rate concept which is, in essence, a national

rate concept with respect to “new gas” supplies. A fur-

ther consideration which supports our conclusion that a

“locational value” concept should be rejected in this pro-

ceeding is the fact that it would be counter-productive

during an acute gas shortage te ose an economic penalty

on natural gas supplies to be discovered in the more pro-

lific areas which are located at great distances from the

major centers of consumption.

Several parties herein have challenged our use of rule-

making procedures in this proceeding.'® The thrust of

their contentions is that the Fifth Amendment of the

United States Constitution, the Natural Gas Act, 15

15. Amerada Hess Corporation, American Public Gas Association

(APGA), Chevron Oil Company, Western Division, Exxon Corpora-

tion, Marathon Oil Company, Mobil Oil Corporation, Phillips Petro-

leum Company, Public Utilities Commission of the State of Colorado,

Superior Oil Corporation, Texaco Inc., The California Company, a

division of Chevron Oil Co., and Senator James G. Abourezk.

Associated Gas Distributors (AGD) urged the Commission to allow

oral argument, but did not oppose the use of rulemaking procedures

to establish rates.

C-11

[2641]

U.S.C. §717, et seqg., and the Administrative Procedure

Act, 5 U.S.C. §551, et seqg., require the Commission to

utilize formal adjudicatory procedures in ratemaking pro-

ceedings. This particular issue has been before the Courts

in several recent cases, and in each instance the Com-

mission’s authority to establish rates via rulemaking was

upheld. American Public Gas Association, et al. v. F.P.C.,

Nos. 71-1812 and 71-1873 (D.C. Cir., May 23, 1974);

Mobil Oil Corporation v. F.P.C., ___U.S. App. D.C.

, 483 F.2d 1238 (D.C. Cir. 1973); Phillips Petro-

leum Co. v. F.P.C., 475 F.2d 842 (10th Cir. 1973),

cert. denied sub nom. Chevron Oil Co., et al. v. F.P.C.

No. 73-91, 42 U.S.L.W. 3401 (U.S., January 14, 1974).

[2642]

This is not the first time that this Commission has

utilized its rulemaking powers to establish rates. In ad-

dition to the proceedings reviewed by the Tenth Circuit

in the Phillips case and the proceedings reviewed by the

D.C. Circuit in the APGA case, the Commission utilized

its rulemaking authority, after strict compliance with the

Administrtive Procedure Act (5 U.S.C. $551, et seq.),

to establish just and reasonable rates for “old” and “new”

gas and to impose an indefinite moratorium on rate in-

crease filings with respect to natural gas produced in the

Appalachian and Illinois Basin Areas.** The Comunis-

sion’s decision in that proceeding was not appealed.

Furthermore, the petitions to review Opinion No. 658,""

16. Area Rates For The Appalachian And Illinois Basin Areas,

et al., Docket No. R-371, et al., Order No. 411, 44 F.P.C. 1112

(1970), as amended, Order No. 411-A, 44 F.P.C. 1334 (1970), reh.

denied, Order No. 411-B, 44 F.P.C. 1487 (1970).

17. Area Rates For The Rocky Mountain Area, Docket No. R-

425, Opinion No. 658, 49 F.P.C. 924 (issued April 11, 1973), appeal

C-12

|

[2643]

which established just and reasonable rates for natural

gas sold under contracts dated prior to October 1, 1968,

and produced from wells drilled (commenced) prior to

January 1, 1973, and made the initial rates established

in Order No. 435'° applicable to natural gas sold under

contracts dated between October 1, 1968, and June 17,

1970, until sdch time as a final order is issued in this pro-

ceeding, were dismissed pursuant to a motion filed by the

petitioners (Exxon Corporation, et al.) on February 22,

1974.

[2643]

It is settled that the United States Constitution does

not require the use of formal adjudicatory procedures in

ratemaking proceedings by this Commission where, as

here, ile rates established will apply to groups generally

and no effort is made to single out any individual or

company “for special consideration based on its own

peculiar circumstances.” United States v. Florida East

Coast Ry., et al., 410 U.S. 224, 246 (1973); Mobil Oil

Corp. v. FPC, 483 F.2d 1238, 1250; APGA, et al. v.

FPC, slip opinion at p. 10. Therefore, any question as to

the adequacy of the procedures followed in this case

reduces to whether or not the procedures satisfy ihe

requirements of the Natural Gas Act and the Adminis-

trative Procedure Act.

pending sub nom. Exxon Corporation, et al. v. FPC, No. 73-1854

(D.C. Cir. filed August 6, 1973), motion to dismiss appeal granted

February 22, 1974.

18. Initial Rates For Future Sales Of Natural Gas For Ali Areas,

Docket Nos. R-389 and R-389-A, Order No. 435, 46 F.P.C. 68

(1971), affirmed sub nom. American Public Gas Association v. F P.C.,

No. 71-1812 (D.C. Cir., decided May 23, 1974).

C-13

[2643]

We believe that any question as to the adequacy of the

procedures followed in this case that may have been

raised by the Mobil Oil decision where laid to rest by the

subsequent decision of the Supreme Court not to review

the Phillips decision. Moreover, the Court of Appeals for

the District of Columbia Circuit has distinguished its

holding in the Mobil Oil case in its holding that the Com-

mission has the authority to establish initial rates by the

use of rulemaking procedures. American Public Gas

Association, et al. v. FPC, Nos. 71-1812 and 71-1873

(D.C. Cir., decided May 23, 1974).

In the Mobil Oil case, the Commission’s order was

reversed on the basis of an inadequate record and lack of

proper notice to the various parties. It was on this basis

that the Mobil case was distinguished in APGA, et al. v.

FPC, supra, slip opinion at p. 10:

In the Mobil Oil case there was no adequate notice,

and much of the data relied upon by the Commission

was provided in an informal and to some extent

ex parte conference, as distinguished from an ad-

versary setting.

We have, in this proceeding, provided adequate notice

to all interested persons with respect to the proposed goal

of the Commission and the type of information and data

upon which

[2644]

our decision would be based. Indeed, a second notice

enumerating specific questions upon which the Commis-

sion desired additional comments was served upon all

parties of record.

While the APGA case dealt with initial rates, we are

of the opinion that the same rationale applies to the

C-14

[2645]

establishment of just and reasonable rates. The Court

there found that the Commission’s procedures were con-

sistent with the due process rights of the petitioners and

stated (slip opinion, p. 10):

The issues were clearly stated from the onset and

the petitioners were given an adequate opportunity

to participate in developing evidence bearing upon

those issues. There is no reason to believe that the

exchanges or dialogue between and among the parties

were so inadequate as a mechanism for finding the

facts that a trial-type proceeding was necessary.

Likewise, in this proceeding, every party has been given

an opportunity to submit two sets of responses and replies

to the responses of all other parties. Thus, no party can

be heard to complain that he lacked an adequate oppor-

tunity to develop his case before the Commission.*®

Since the Natural Gas Act does not require a “hearing

on the record” in ratemaking proceedings,*’ the Commis-

sion is not required to hold an adjudicatory hearing under

the

[2645]

formal procedures set forth in Sections 556 and 557 of

the Administrative Procedure Act, 5 U.S.C. §§556 and

557, before establishing generally applicable producer

rates. As the Court noted in APGA, et al. v. FPC, supra,

19. In the April 12, 1974, order in this proceeding, we emphasized

the right of all parties to file “any comments which they desire to

place before the Commission for consideration.” (Mimeo, p. 3, foot-

note omitted. )

20. Section 4(e), 15 U.S.C. §717c(e), and Section 5(a), 15 U.S.C.

§717d(a), require a “full hearing” and a “hearing”, respectively, be-

fore the Cormmission exercises its authority to establish “just and

reasonable” rates.

C-15

[2645]

a trial is not a prerequisite to the establishment of rates

(slip opinion, p. 7):

The Commission is not forced to adopt the pro-

cedures of a trial, with formal hearings, oral testi-

mony under oath, cross examination, and the like.

Evidentiary submission in written form may be suf-

ficient. United States v. Florida East Coast Rwy Co.,

410 U.S. 224 (1973); FPC v. Texaco, Inc., 377 U.S.

33, rehearing denied, 377 U.S. 984 (1964); Mobil

Oil Corp. v. FPC, ___ U.S. App. D.C. ___, 483

F.2d 1238 (1973).

Thus, we find that the procedures adopted in this pro-

ceeding which allowed the filing of two sets of initial and

reply comments by all parties provide a sufficient basis

for the acquisition of the information which we require

in order to arrive at a final decision.

Furthermore, we find no basis or need for a formal

hearing with oral cross examination in this proceeding.

While the parties have not been given an opportunity to

orally cross examine the statements of the other parties

to this proceeding, they have been given an opportunity

to file any and all comments they desire to file. Even the

Administrative Procedure Act does not provide an un-

trammelled right to oral cross examination in formal pro-

ceedings. Section 556(d), 5 U.S.C. §556(d), provides

in part:

A party is entitled to present his case or defense by

oral or documentary evidence, to submit rebuttal

evidence, and to conduct such cross examination as

may be required for a full and true disclosure of the

facts. In rulemaking . . . an agency may, when a

C-16

[2646]

party will not be prejudiced thereby, adopt pro-

cedures for the submission of all or part of the evi-

dence in written form.

[2646]

Those parties who have asserted a right to oral cross

examination in this proceeding have failed to demonstrate

that they will be prejudiced by the lack of such cross

examination in this proceeding. No party has pointed out

any specific questions or issues that it would raise upon

oral cross examination or why it could not adequately

“test, criticize, and illuminate the flaws in the evidentiary

basis being advanced regarding a particular point” by

other parties in its own written submissions. (See Mobil

Oil Corp. v. FPC, 483 F.2d 1238, 1262-1263). In such

circumstances, we are not required to speculate as to

whether or not there are issues or questions which re-

quire oral cross examination. Our examination of the

submittals of all parties to this proceeding discloses no

issue which requires a formal adjudicatory hearing with

oral cross examination.”

Because our decision must be based upon substantial

evidence contained in the record of the proceeding as a

whole, we are of the opinion that we should set forth

those documents which constitute the evidentiary record

of this proceeding so that all parties will be aware of all

the evidence which was considered by the Commission

21. An on-the-record public conference was held in this proceeding

on April 16, 1974, at the request of the American Gas Association

(AGA) to discuss Appendix B-1 to the notice issued March 21, 1974,

in this proceeding. Certain parties which have questioned our use of

AGA reserve data did not participate in the conference, yet they

continue to oppose the use of such data and demand a formal hearing

on the issue.

C-17

[2646]

in reaching its decision.*” The evidentiary record of this

proceeding will consist of (1) the notice of rulemaking

and the Staff cost study appended thereto which were

issued on

[2647]

April 11, 1973 (38 Fed. Reg. 10014 (1973)); (2) the

notices filed by the various parties of the intention to

respond to the notice of proposed rulemaking which were

required to be filed on or before April 30, 1973; (3) the

written comments of all parties, including the various

cost studies and other evidentiary materials submitted

therewith, filed on or before May 16, 1973, and on or

before June 1, 1973; (4) the notice of March 21, 1974

(39 Fed. Reg. 11310 (1974)); (5) the notices of the

public conference held in this proceeding on April 16,

1974 (39 Fed. Reg. 12929, 13199 (1974)); (6) the

order of April 12, 1974 (39 Fed. Reg. 13976 (1974));

(7) the transcript of the April 16, 1974, conference in

this proceeding;** (8) the comments filed by the parties

to this proceeding on or before May 7, 1974, and on or

before May 29, 1974; and (9) the materials incorporated

by reference into the record of this proceeding as herein-

after set forth.**

22. Mobil Oil Corp. v. FPC, 483 F.2d 1238 at 1258-1260 (1973);

American Public Gas Association, et al. v. FPC, supra, slip opinion

at p. 8 citing United States v. Floride East Coast Rwy. Co., 410 US.

224, 241 (1973).

23. The transcript consists of one volume containing 73 pages.

24. All late filings in this proceeding are deemed to have been

timely filed and have been considered by the Commission.

C-18

Pinna eten teen. + Datei a ree o w0n —

[2648]

(2648)

II

SUPPLY AND DEMAND

A. SUPPLY

1. THE NATURAL GAS SHORTAGE

The pervasive natural gas shortage, which this nation

is currently experiencing and which is expected to con-

tinue beyond the 1980's, requires that this Commission

promulgate producer pricing policies which will attract

long-term dedications of new natural gas supplies to the

interstate market. |

As can be seen in Table 1, the natural gas reserves

reported by jurisdictional pipelines have declined from

~ 198.1 trillion cubic feet (Tcf) in 1967 to a low of 148.6

Tcf in 1972. This represents a decline of approximately

50 Tcf in a six year period, and the decline was also

approximately 25 percent of the reserves existing in

1967.*° During this same six-year period (1967 through

1972), the findings to production ratio (F/P) averaged

around 0.5; this means that the consumption of natural

gas was approximately twice the new supplies of natural

gas discovered during the period. These trends must be

reversed if we are to meet future demands for natural gas.

Our analysis of beth oil and gas drilling activities

since 1945 indicates that there has been a decline in

exploratory and developmental drilling in recent years.

We believe that this decline in drilling activity is, at

25. Preliminary data reported by pipelines on Form 15 for 1973

shows reported reserves are 134.4 [cf or a decline of 63.7 Tcf since

1967. ;

C-19

[2648]

least in part, responsible for the decline in new natural

gas supplies discovered in recent years. This downward

trend must be reversed if we expect to meet essential

demands for natural gas from domestic sources and attain’

our objective of a national capacity for self-sufficiency

in energy resources. Thus, one of the primary goals which

we have in establishing a national rate is to set a rate

sufficient to encourage the exploratory and developmental

drilling which is required to discover and produce the

natural gas supplies necessary to attain an objective of

self-sufficiency in natural gas supplics available for de-

livery to the ultimate consumer.

te ee eer en 2

TABLE I

AGA and

Form 15 Data (Lower 48 States)

(Volumes in Trillions of Cubic Feet)

Comparison o

Finding to

Production Ratio

Net Reserve to Reserve

Production Ratio Additions

Production

End of Year

Reserves

Form 15

Form 15 AGA Form 15

AGA

Form 15 AGA Form 15 AGA

AGA

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[2649]

[2650]

[2650]

Table 2 shows that in 1956 some 30,528 domestic oil

wells were drilled as compared to a total of only 11,306

oil wells drilled in 1972. Gas-well drilling has shown

a similar decline from the peak of gas-well drilling activi-

ties in 1961 when some 5,459 successful gas wells were

completed as compared to a total of only 3,830 gas wells

completed in 1971. This downward trend in gas-well

drilling was reversed in 1972 when 4,928 gas wells were

completed, and it continued through 1973 when some

6,385 gas wells were drilled as compared to 4,928 gas

wells drilled in 1972.*°

As indicated by Table 3, the total number of explora-

tory wells drilled has declined sharply since 1964 and ex-

ploratory gas-well drilling for 1967 through 1972 was at

lower levels than the preceding decade. Both the total

number of wells drilled and the total number of explora-

tory wells drilled per year for the past five to six years

are considerably fewer than the total number of wells

dritled and the total number of exploratory wells drilled

approximately 15 years ago while the demand for oil and

gas has doubled in that 15 year period.

The reversal of drilling activity which occurred in 1972

did not carry through to 1973 with the exception of the

number of gas wells completed which again increased over

the number completed the previous year. Overall, 1973

showed a continued increase in gas drilling activity with

both exploratory and developmental gas well footages at

26. FPC Office of Economics, Gas Supply Indicators—Fourth

Quarter 1973 and Annual Review, April 1974, p. 21.

C-22

——

A RE OU Be nec ee ne

[2650]

ll

the highest levels ever reported.*’? The number of oil wells

drilled in 1973 continued to decline over the numoer

drilled in previous years. There were other encouraging

signs in that number of rotary drilling rigs which were

active during the year was the highest active number since

1966. Other indicators seemed to show a leveling off in

the increased activity as bottlenecks and supply shortages

began to appear in the fourth quarter of 1973.**

27. Id., p. 12. The total footage for 1973 was 33.0 million feet

compared with the previous high of 29.1 million feet in 1961.

28. ZId., p. 8.

[2652]

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@ A1VL

[2653]

[2653]

This continued upturn in gas well exploratory and

developmental drilling is not adequate to discover ana

bring forth the supply of natural gas necessary to meet

projected demands in view of the continued decline in

annual additions to the nation’s non-associated gas re-

serves.*” Moreover, the continued decline in oil-well drill-

ing activity means not only a short fall of domestic crude

oil supplies but also a short fall of supplies of dissolved

and associated gas that will be available for consumption.

Unless we increase domestic exploratory and develop-

mental drilling for both crude oil and natural gas, the

Staff's forecast of annual natural gas supply deficits of

9 Tcf by 1980 and 17 Tef by 1990 will become painfully

true.*"

[2654]

The magnitude of the drilling effort which will be

required to elicit the supply of natural gas necessary to

fulfill reasonable future demands is staggering. It is esti-

mated that annual findings in the range of 37 trillion cubic

feet will be required to meet the demand:

If we assume that an adequate reserves to pro-

duction ratio of about 10 is maintained; that a rea-

sonably optimistic development of supplemental gas

sources is attained with respect to overland imports,

LNG imports, gas from coal, and gas from Alaska;

29. Production has exceeded annual reserve additions for every

year since 1967. (See Table 1, supra p. 17) and reserve additions for

1973 were the lowest reported since the American Gas Association

first published its report in 1946.

30. Federal Power Commission, Bureau of Natural Gas, National

Gas Supply and Demand 1971-1990—Staff Report No. 2, p. 1, Feb-

ruary 1972,

C-26

[2655]

that the industry is capable of immediately mounting

an all-out exploration and development program un-

impeded by financial, equipment or manpower con-

siderations; then an annual finding rate of approxi-

mately 37 trillion cubic feet per year would be neces-

sary to bring supply and demand into balance. While

this rate of resource development does not include

an allowance for the unknown impact of higher gas

prices on demand, it is nonetheless sobering to realize

that this level of development represents a sustained

level of annual additions to reserves equal to that

attained in 1970 when 2v trillion cubic feet of

Alaskan gas were added to the reserve inventory,

or an amount equal to 12 times the all-time record

annual lower 48 reserve additions of 24.7 trillion

cubic feet reached in 1956. Attainment of this level

of resource development would require the cumula-

tive discovery and development of about 666 trillion

cubic feet of natural gas to 1990, representing the

development of approximately 58 percent of the

Nation’s total potential gas supply as estimated by

the Potential Gas Committee. This rate of develop-

ment would be required in conjunction with the

timely development of supplemental gas supplies and

would be substantially higher in the absence of such

supplemental supply availability.”’

|2655]

The supplemental gas supplies anticipated in the years

1975, 1980, 1985, and 1990 for this estimate are 1.5 Tcf

31. Letter from John N. Nassikas (Chairman, Federal Power

Commission) to Senator Henry M. Jacksen, September 12, 1973.

Material quoted is contained in comments of Bureau of Natural Gas

on Senate Interior and Insule. Affairs Committee Staff Draft, “Policy

Issues and Options Affecting Natural Gas.”

C-27

[2655]

4.6 Tcf, 7.6 Tcf, and 11.5 Tcf respectively. The individual

components of the 1990 supplemental supply are estimated

as follows: pipeline imports—1.9 Tcf; LNG imports—

4.0 Tcf; high Btu gas from coal—3.3 Tcf; and gas from

Alaska—2.3 Tcf.*”

The magnitude of the exploration and development ef-

forts that will be required to bring forth these volumes

of annual additions is further magnified by the fact that

with the exception of 1970 and 1956 annual additions

over any period of time have been less than two-thirds of

the required findings.** Thus, if the demand for natural

gas is to be fulfilled,** the natural gas industry must attain

and sustain a findings rate that it has never before with

one exception attained. Whether or not this level of re-

serve additions can be attained and maintained is a ques-

tion that can be answered only with the passage of time.

It is clear, however, that massive capital commitments

will be called for to finance the exploration and develop-

ment programs necessary to find and produce the supplies

so as to fulfill the projected demand.

[2656]

The Commission’s regulatory obligation is to establish

a uniform national rate in this proceeding that provides

32. Federal Power Commission Bureau of Natural Gas, National

Gas Supply And Demand 1971-1990, Staff Report No. 2, p. 136

(Table 20) (1972).

These supply levels are based upon an annual demand of 46.4 Tcf

and assume that domestic reserve additions will be sufficient to fulfill

all demand that is not fulfilled by the supplemental supplies and re-

plenish the nation’s inventory of reserves such that the reserves re-

maining at the year end are ten times the annual production.

33. American Gas Association, Gas Supply Review Supplement,

p. 2 (Table 1) (May 15, 1974).

34. Seen. 30 supra, p. 136 (Table 20).

-2

[2657]

the incentives to stimulate and encourage the unprece-

dented exploration and development efforts that will be

necessary to find and produce the requisite level of new

natural gas supplies. We further seek to reduce the exist-

ing disparity between supply and demand, to effect a

more efficient allocation of our existing natural gas re-

sources to higher priority uses, and to encourage the con-

servation of the limited natural gas reserves which are

available to us.

[2657]

2. QUANTIFYING THE SUPPLY-PRICE

RELATIONSHIP

While the efficacy of producer rate regulation would

be greatly enhanced if it were possible to quantify the

amount of reserves that wou!d be forthcoming at a given

rate level, it is generally conceded that there is no reliable

method by which this quantification can be made.** The

supply-price relationship has been given extensive atten-

tion in several area rate proceedings. In the first Permian

Basin area rate proceeding, the Commission noted the

emerging price-supply relationship:

[T]he emergence of directionality, i.e., the ability of

producers to direct their drilling activities toward

either oil or gas brings in to being for the first time

an opportunity for price to play a significant role

in increasing the supply of gas-well gas available to

the interstate market.

35. Cf. Public Service Commission For The State Of New York

v. FPC, U.S. App. D.C.____, 487 F.2d 1043 at 1089-1090,

1095-1099 (D.C. Cir. 1973), cert. granted, vacated and remanded,

Nos. 73-966, et al., June 17, 1974.

C-29

[2657]

Area Rate Proceeding (Permian Bain), 34 F.P.C. 159,

184 (1965). This proceeding also saw the first econometric

studies of the gas producing industry which the Commission

viewed as “indicat[ing] that advanced statistical and mathe

matical techniques can be useful in understanding the inter-

action of the price of gas at the wellhead and the demand

in the marketplace.” 34 F.P.C. 159 at 187. However, this

first model was “based on a nondirectional hypothesis”,

and “a materially different equation would [have been]

required” if a directional hypothesis had been used. 34

F.P.C. 159 at 332 (Initial Decision Of The Presiding

Examiner). Because of these shortcomings, the econo-

metric study did not play a role in the Commission’s

decision.

In the first Southern Louisiana Area Rate Proceeding,

the Commission and the Hearing Examiner had before

them a new econometric study which was also found to

be unreliable. The utility and accuracy of this new

econometric model was viewed in the following manner:

[2658]

[W]e do not claim that the efficiency of producer

regulation cannot be improved with the aid of econo-

metrics and other analytical tools . . . . Should the

industry as well as the Staff find it possible to pursue

similarly innovative analytical efforts in the years

ahead, more reliable results may well be achieved

and the regulatory process will be benefitted.

Area Rate Proceeding (Southern Louisiana Area), 40

F.P.C. 530, 625-626 (1968).*°

36. With respect to this model, the Presiding Hearing Examiner

noted:

It might be properly suggested that enough has already been

C-30

[2659]

The latest econometric model to be presented to the

Commission was introduced by the Staff in the second

Southern Louisiana Area Rate Proceeding and was again

found to be lacking as an evidentiary basis for determin-

ing supply elasticity:

[T]he model provides an analytical format for the

application of judgment in a more systematic fashion,

and it is useful, in a general way, for testing the

judgments implicit in this decision. The Commission

. . . interprets the model not as a formula to obtain

precise quantification of the

[2659]

future supply response to prices—an impossible ob-

jective by any method in our view—but as an instruc-

tive experimental effort, complementing other ex-

hibits and testimony upon which we may rely for

our specific findings and conclusion.

Area Rate Proceeding, et al. (Southern Louisiana Area),

46 F.P.C. 86, 123 (1971).

In this same proceeding, the Commission found that:

The response of the natural gas industry to the price

of the gas, whether that price is fixed by the FPC

demonstrated to indicate that econometric studies ultimately, on

the basis of still further study and improvement by the Staff,

may one day be brought to the point where they will provide

a significant, useful and reliable tool in this connection. . . .

However, it must be concluded on the basis of the record made

in the instant proceeding that the econometric presentation here

made by the Staff has not yet reached the level where it can

safely be relied upon as a basis for the Commission's critical

conclusions in this case.

40 F.P.C. 530 at 871-872 (Initial Decision of the Presiding Hearing

Examiner).

C-31

[2659]

or by other market forces, can only be predicted by

assuming that a great number of other factors are

going to remain constant. There is no way for any

record to prove that such will be the case, and at

this moment in history there is every reason to

assume that such assumptions are not even much

good for the making of academic studies. The area

is judgmental in the extreme.

[P]rogress is being made in devising techniques for

extrapolating the trends evident from market and

investment performance in the past into useful guides

for determining what regulators should do in fixing

prices or other matter to control future conduct.

46 F.P.C, 86 at 120-121. These findings formed the basis

for the Commission’s conclusion that there was a positive

relationship between the price of gas and exploratory

effort, but that:

the conventional concept of supply elasticity—com-

monly defined as the quantities which would be

forthcoming at a given time at a particular price—

is a concept exceedingly difficult to apply to natural

gas. The many variables other than price, such as

technology and cost of input resources, cannot be

readily ascertained.

46 F.P.C. 86 at 121.

[2660]

The Commission then concluded:

Summarizing, there exists a positive relationship

between gas contract price levels and exploratory

effort; no reliable quantitative forecasts may be made

by increments of additional gas supply resulting

C-32

ee

[2661]

from specific increased gas prices; increases in ceil-

ing prices which yield increases in producer revenues

will result in expanded gas exploratory activity in

terms of sufficiency of gas supply in relation to gas

demands must be determined by continued Commis-

sion observation of the results of our decisions.

46 F.P.C. 86 at 124.*

These conclusions are still valid. While further quanti-

tative studies of the elasticity of gas supply with respect

to the wellhead price should be encouraged, this case must

be decided upon the record that is before the Commis-

sion,** and the experience gained from previous considera-

tions of this

[2661]

question demonstrates that reliable quantification is not

possible with the present state of the art.*°

37. In its affirmance of the Commission’s decision in the second

Southern Louisiana Area Rate Proceeding, the Fifth Circuit reviewed

the problems associated with predicting the level of new gas supplies

that would be forthcoming at a given rate and stated that “it is

impossible with any degree of precision likely to satisfy the momen-

tary opponent’s fetish for qualification to determine the likely quan-

titative effect on supply of a change in the rate ceiling.” Placid Oil

Co. et al. v. FPC, 483 F.2d 880, 901 (Sth Cir. 1973) The Supreme

Court has agreed with the Commission “that it [the Commission]

could not determine the precise amount of additional gas supply that

would be found and dedicated to interstate sales as a result of this

formula. But this was also true of any change it might have made in

gas prices. Mobil Oil Corp. v. FPC, 42 U.S.L.W. 4842 (US. June 10,

1974) (Slip Opinion at 31). Moreover, the Court found that the

Commission’s findings were supported by the record (Slip Opinion at

p. 32).

38. Mobil Oil Corp. v. FPC, U.S. App. D.C. , 483 F.2d

1238 (D.C. Cir. 1973).

39. See Foster Associates, Inc., The Impact Of Deregulation On

Natural Gas Prices, Appendix C (1973), for a discussion of the prob-

C-33

[2661]

The historical record demonstrates in a general manner

the responsiveness of gas supply to price. During the

1960’s gas prices trended downward, when adjusted for

general inflation and gas well exploratory and develop-

mental drilling also turned downward. Toward the end

of the decade, the gross annual additions to gas reserves

experienced a sharp decline and negative revisions in-

creased sharply.*® The first signs of a turnaround in drill-

ing activity appeared in 1972, a year or so after the trend

of declining real prices for natural gas had been reversed.

The number of new gas wells drilled increased 28.7 per-

cent from 1971 to 1972, while the increase in exploratory

gas well footage was 38.0 percent. This level of drilling

activity continued through 1973; for example, for 1973

exploratory gas well footage increased some 34.8 percent

above the level for 1972 and developmental gas-well

footage increased by 21.8 percent over the footage drilled

[2662]

in 1972. However, marketed production of natural gas

for 1973 showed a decline over 1972.*' Whether these

lems encountered in the various attempts to develop an econometric

modei of the supply-price relationship for natural gas and a summary

of recent efforts to develop a model.

See also, MacAvoy and Pindyck, “Alternative Regulatory Policies

For Dealing With The Natural Gas Shortage,” 4 The Bell Journal of

Economics and Management Science 454 (Autumn 1973); Breyer and

MacAvoy, “The Natural Gas Shortage And The Regulation Of Nat-

ural Gas Producers,” 86 Harv. L. Rev. 941 (1973); MacAvoy, “The

Regulation-Induced Shortage Of Natural Gas,” 14 J. Law & Econ.

167 (1971); Erickson and Spann, “Supply Response In A Regulated

Industry: The Case Of Natural Gas,” 2 The Bell Journal Of Eco-

nomics And Management Science 94 (1971).

40. See Appendix A.

41. FPC Office of Economics, Gas Supply Indicators — Fourth

Quarter, 1973 and Annual Review, April 1974, p. 6.

C-34

ee ee ee

aoe SO

[2663]

increases in drilling activity will bring about an impzove-

ment in new additions to natural gas reserves remains to

be seen since the reserve additions for 1972 were as the

same low level experienced in 1971. (See Appendices

A and C (Schedule 2, Sheet 1)). Furthermore, the re-

serve additions for 1973 were only 6.51 Tcf, the lowest

addition reported since the data on reserve additions has

been reported. See n. 33 supra.

[2663]

Thus, it is concluded that an increase in the price at

which natural gas may be sold in the interstate market

will have the effect cf bringing forth new supplies of

natural gas for dedication to the interstate market; how-

ever, it is not possible to predict or quantify the precise

ievel of new supplies that will be forthcoming at the rate

established herein. To attempt to further define this rela-

tionship would be to “demand the perfect at the expense

of the achievable.”*” .

B. DEMAND

There is little doubt today that the demand for natural

gas is far in excess of the available supply and will re-

main in excess of the available supply for the immediate

future.** This difference between the available supply

See Appendix C (Statement of J. Rhoads Foster) to the comments

filed by the Indicated Producer Respondents for information to the

same effect. Chart I in Dr. Foster's statement shows a positive rela-

tionship between the initial price for new gas sales and the level of

exploratory gas drilling in seven southwestern states for 1947 to 1970.

42. Public Service Commission For The State of New York v.

FPC, U.S. App. D.C.__, 487 F.2d 1043 at 1067 (D.C. Cir.

1973) (Leventhal, J., dissenting).

43. Bureau of Natural Gas, Nationc: Gas Supply and Demand

1971-1990—Staff Report No. 2 (1972).

C-35

[2663]

and the total existing demand constitutes the natural gas

shortage. The most direct evidence of this shortage is the

continuing curtailment of deliveries by the interstate pipe-

lines.**

The pervasive natural gas shortage which we are now

enduring has had and will continue to have serious eco-

nomic consequences for the nation. In Order No. 491

(supra, n. 4), the Commission outlined the effect of

curtailment of natural gas supply for the major interstate

pipelines as follows (mimeo, p. 2):

[2664]

Such curtailments will result, as they did last year,

in severe economic and environmental consequences,

resulting in the closing of schools, the denial of

~ utility service to new customers, the utilization by

industry and electric utilities of alternate fuels which

impact upon ambient air quality standards, and the

transfer of unfulfilled demand to other fuels in short

supply with the resultant upward price pressures.

In Order No. 491-A (supra, n. 4), we expanded our

analysis of the effects of continued curtailment (mimeo,

pp. 3-4):

44. Bureau of Natural Gas, Staff Report on Interstate Natural

Gas Pipeline Curtailments, FPC Release No. 19640, September 17,

1973.

Hearing on Relationship of Energy and Fuel Storages to the Na-

tion's Internal Development Before the Subcommittee on Flood Con-

trol and Internal Development of the House Committee on Public

Works, 92d Cong., 2d Sess. 58-9 (1972) (Energy and Fuel Shortages

hearings).

See also, Statement of Chairman John N. Nassikas, Federal Power

Commission, Hearing Before the Subcommittee on Activities of Reg-

ulatory Agencies of the Select Committee on Small Business, U. S.

House of Representatives, January 17, 1974.

C-36

[2664]

Our staff's revised report indicates (after eliminating

inter-company transactions) that eleven of thirty-

three reporting companies had experienced curtail-

ments of approximately .4 trillion cubic feet for the

period April through October 1972 (summer season).

For the same period in 1973, thirteen companies re-

ported actual and estimated curtailments [April

through July volumes were actual, whereas August

through October volumes were estimated] totaling

slightly more than .7 trillion cubic feet. This repre-

sents an increase in curtailments of 75 percent over

the same period one year ago. Similarly, fifteen

companies reported actual curtailments of .4 trillion

cubic feet during the period November 1972 through

March 1973 (winter season). For the approaching

1973-74 winter season, fourteen companies esti-

mated curtailments totaling approximately .5 trillion

cubic feet—an increase of 25 percent. Furthermore,

the supply deficiencies for the 1973-74 heating season

which were projected in the July 1973 report have

substantially increased in the September report. This

indicates that the major pipelines are experiencing

increasing difficulty in obtaining sufficient gas to

maintain reliable service. The following table repre-

sents the extent of curtailed service each of the major

pipeline companies projects for the 1973-74 season

(April 1973 through March 1974):

C-37

[2665]

[2665]

Firm Volumes

Requirement Curtailed Percent

Mcf Mei Curtailment

* Algonquin 177,935,800 17,431,500 10.0

Arkansas-Louisiana 495,548,000 119,877,965 24.0

Cities 571,164,000 29,856,000 5.0

Columbia 1,532,573,000 12,574,000 1.0

El Paso 1,906,747 ,000 147,474,427 8.0

*Louisiana-Nevada 147,271,334 56,700* Negligible

Mississippi River 209,296,000 7,996,118 4.0

Natural 1,207,139,000 228,868,178* 19.0

Northern 896,000,000 11,800,000 1.0

Panhandle 825,708,000 36,079,308 4.0

Texas Eastern 1,081,814,000 164,503,788 15.0

Transco 1,097,152,000 141,018,748 13.0

Transwestern 360,532,000 20,759,957 6.0

Trunkline 507,986,000 165,601,429 —«-28.0

United Gas 1,602 ,798,000 541,937,052 34.0

*Summer curtailment only.

Furthermore, all of the above pipelines, with the

exception of Aigonquin and Louisiana-Nevada, have

been obtaining some gas under the Commission’s

present emergency purchase provisions. The projected

curtailments would thus be even greater without the

increments provided by such temporary purchases.

{Footnote included in text.]*°

45. An FPC Staff Report issued on June 11, 1974 indicates that

natural gas supply deficiencies for the major interstate natural gas

companies from the April 1974 through March 1975 period will be

nearly 55°% higher than a year earlier. The report, by the FPC’s

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a oe

Mite ntti oes

[2667]

Finally, in Order No. 491-B (supra, n. 4), we noted that

there was not only a natural gas shortage, but also a

national energy emergency (mimeo, p. 5):

In Order No. 491-A, we further observed that

problems created by the natural gas shortage are

exacerbated by the fact that other fuels, such as

propane and fuel oil, are in short supply.

[2667]

We reviewed the problems associated with the short supply

of propane and concluded that “curtailments of natural

gas this winter will force many industrial plants to operate

part-time or shut down completely. Many of these plants

could have relied upon propane as a satisfactory alternate

fuel.” Order No. 491-A, mimeo, p. 6. But, we noted that

testimony before the September 7, 1973, hearing held

by the White House Energy Policy Office indicated that

supplies of propane for the 1973-74 heating season would

be approximately 15 to 25 percent less than the volumes

available during the 1972-73 heating season and that

mandatory propane allocations were in force. Order No.

491-B, mimeo, p. 5 at n. 7. The short supply of fuel oil

available to industrial consumers held out the potential

for plant slow-downs or actual shut-downs since neither

natural gas nor fuel oil were expected to be available in

Bureau of Natural Gas, based on responses to the Commission’s Form

16, shows that actual or projected curtailments were reported by 17

out of 42 major interstate pipeline companies. Net curtailments to-

taled 1,191,132,000,000 cubic feet for the year April 1973 through

March 1974. Net supply deficiencies totaling 1,845,770,000,000 cubic

feet are projected for the year April 1974 through March 197°. Cu-

mulative net curtailments of firm service imposed by all companies

reporting these data to the Commission since 1970 amounted to

approximately 2.4 Tcf through the first quarter of 1974.

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[2667]

sufficient quantities for full industrial operation. See Order

No. 491-A, mimeo, p. 7.

While a mild winter and the fact that greater than

anticipated supplies of fuel oil were available have helped

to reduce the impact of the shortage of fuels derived from

natural gas and crude oil, we find that the nation is still

and will continue to be confronted with a national energy

emergency resulting from a shortage of basic fuels required

to maintain a productive economy. We believe that this

continuing energy emergency requires this Commission

undertake the establishment of policies that will encourage

the development of the additional supplies of natural gas

that are needed to fulfill reasonable demands. The promul-

gation of a single uniform national rate is one of the

policies that will help us to increase the available supply

of natural gas for the nation.

Much of the demand for natural gas comes not only

from its low price, but from its form value*® and its su-

perior environmental qualities. The present prices for

natural gas in relationship to other fuels in the market

make it unlikely that increases in the wellhead price of

natural gas will have a

[2668 |

moderating effect upon the demand for natural gas suf-

ficient to close the supply-demand gap.*’ However, the

ultimate consumption of natural gas can be controlled in

another fashion. It is possible to regulate energy demand

46. The gaseous form of natura! gas facilitates its transportation

and delivery to the customer and eliminates the need for storage

facilities by the final consumer.

47. Appendix B. See also, Appendix B to the Response of the

Indicated Producer Respondents.

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[2669]

met with natural gas to a certain extent by controlling

the priority assigned to the end use of natural gas in the

consumer marketplace, and requiring that all of the

demand assigned to a higher priority is satisfied before

new supplies of gas are allowed to be consumed in end

uses assigned a lower priority.**

The existing demand for natural gas that must be met

first is the demand of the homeowner, the small corm-

mercial establishment, schools, hospitals, and other con-

sumers that can be classified as “human needs” customers.

Quite often, these small consumers are unable to switch

to alternate fuels or to use the pollution control devices

required when alternate fuels are used to meet air quality

standards.*”

The issue is basically one of the optimum allocation of

our limited supplies of natural gas, both now and in the

future. Large industrial and utility consumers of natural

gas must progressively reduce their use of natural gas to

assure its availability to the “human needs” customers.

Those users of natural gas who consume the greatest

quantities of the very limited

[2669]

supply of this fossil fuel should be encouraged (and re-

48. Utilization and Conservation of Natural Resources—Natural

Gas, “Notice Of Proposed Policy Statement With Request For Com-

ments,” Docket No. R-467, 38 Fed. Reg. 1517 (1973); Utilization

and Conservation of Natural Resources—Natural Gas, Docket No.

R-469, Order No. 467, 49 F.P.C. 85 (1973), Order No. 467-A, 49

F.P.C. 217 (1973), Order No. 467-B, 48 F.P.C. 583 (1973), “Order

Denying Motions For Reconsideration, Clarification Or Modification

Of Order No. 467-B,” 49 F.P.C. 1036 (1973). See Order No. 467-C,

39 Fed. Reg. 12984 April 14, 1974.

49. Pollution control devices are more effective when installed on

large industrial and utility equipment than when they are installed

on heating units in homes and other small consumers of natural gas.

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eS. ae nn

[2969]

quired, if necessary) to convert to the consumption of

other fossil fuels of which there are more abundant sup-

plies. By shifting some demand for natural gas to other

fossil fuels, we are able to conserve the available supplies

of this precious energy source for consumption in the

market sectors where it is both impractical to install and

use pollution abatement equipment and uneconomical for

the small consumer of natural gas to purchase such equip-

ment.

The existence of the pervasive supply-demand gap re-

quires this Commission to take all reasonable and pru-

dent steps to (1 increase the supplies of natural gas avail-

able for resale in the interstate market and (2) allocate

the available supplies of natural gas being sold in the in-

terstate market to higher priority uses.’” As the Supreme

Court found in Mobil Oil Corp. v. FPC, 42 U.S.L.W.

4842 (U.S. June 10, 1974) (Slip Opinion at 31-32),

there is credible evidence that gas exploratory activities

are responsive to price, an increase in the price of gas at

the wellhead should encourage greater exploratory activi-

ties, and, in turn, make greater quantities of new gas sup-

plies available for resale in the interstate markets. It is

also very likely that an increase in the price of natural

gas will result in some reallocation of the end use of

natural gas in the final market place. However, very little

is known about the cross elasticities between the demand

50. The actual allocation of natural gas to its ultimate end uses

is within the jurisdiction of the particular state regulatory commission

where the interstate pipeline makes deliveries to the local distribution

company. However, this Commission has the power to determine

which distributors shall be entitled to receive additional supplies of

natural gas from the pipeline, and does, therefore, have some indirect

power to allocate the ultimate use of natural gas sold in interstate

markets. See note 48, supra.

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[2671]

for natural gas and the demand for other fossil fuels, and

it is not possible to accurately predict the results of these

reallocations.*’

[2670]

Although it is unlikely that increases in natural gas

prices will dampen demand to the extent of eliminating

the supply-demand gap, such increases will encourage a

shift to alternative fuels by the industrial and utility sec-

tors of the market place whenever the price of natural gas

exceeds the price of other fuels plus the costs of necessary

environmental controls. Such a shift, however, is not ex-

pected to equal the growing unsatisfied demand for

“human needs” customers in the near future.

[2671]

III.

RATE DESIGN

A. COST FACTORS

In response to the notice of rulemaking issued in this

proceeding on April 11, 1973, and the attached Staff

cost studies, the Indicated Producer Respondents (Pro-

ducers),°” the GHK Company, the United Distribution

Companies (UDC), the Pennzoil Companies, Columbia

Gas Transmission Corporation, and the Associated Gas

Distributors (AGD) submitted various cost studies or cost

analyses. Two of the submitted studies were restricted to

certain geographical areas: the GHK study was limited

51. See, Department of the Interior, Draft Environmental Impact

Statement-—Proposed Deregulation of Natural Gas Prices, Appendix

B, July 17, 1973.

52. The Indicated Producer Respondents is a group of twenty-six

major natural gas producers.

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[2671]

to the Deep Anadarko Basin, and the Columbia Gas

Transmission Corporation’s study reflected the conditions

of the Appalachian and Illinois Basin area only. The

other studies were based on nationwide cost and drilling

data and utilized the procedures adopted by the Com-

mission in Opinion No. 598.°* The Pennzoil study also

referred to the procedures adopted in Permian 1.°* AGD

suggested a rate of 45.0 cents per Mcf based upon Staff's

high cost estimate of 38.5 cents per Mcf with an addi-

tional allowance of 6.5 cents per Mcf for increased ex-

ploration and development.

In response to the March 21, 1974 notice and the at-

tached Staff cost studies, UDC and GHK submitted new

cost studies. The Producers submitted studies which were

revisions of their original submittals to reflect full cost

accounting and an allowance for Federal income taxes.

AGD reiterated its recommendation for a rate of 45.0

cents per Mcf. The details of these studies will be dis-

cussed infra.

[2672]

Our cost analysis in this decision is based upon the

methodology which was developed in the first Permian

Basin area rate proceeding, Area Rate Proceeding, et al.

(Permian Basin), 34 F.P.C. 159 (1965), affirmed, Per-

mian Basin Area Rate Cases, 390 U.S. 747 (1968), and

modified in the second Southern Louisiana proceeding,

Area Rate Proceeding, et al. (Southern Louisiana Area),

53. Area Rate Proceeding, et al. (Southern Louisiana Area), 46

FPC 86 (1971).

54. Area Rate Proceeding, et al. (Permian Basin), 34 FPC 159

(1965).

The Pennzoil study also reflected full-cost accounting and an allow-

ance for federal income taxes.

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[2673]

46 F.P.C. 86 (1971), affirmed, Placid Oil Company, et

al, v. F.P.C. 483 F.2d 880 (Sth Cir. 1973), affirmed sub

nom. Mobil Oil Corporation, et al. v. F.P.C., 42 US.

L.W. 4842 (U.S. June 10, 1974). Because the costing

model relies upon a number of allocations which are based

upon flowing gas costs, we shall use the allocation factors

which were updated by use of the data submitted to the

Commission in response to the questionaire in the second

Southern Louisiana proceeding (referred to as the AR69-

1 questionaire). This is the most recent information avail-

able to the Commission with respect to a number of the

allocation factors; however, data submitted to the Com-

mission in the data collection forms which were filed in

Docket No. R-478 will help update these factors.°° When

this data becomes available in final form, it will be incor-

porated into the records of future proceedings to deter-

mine national rates so that these allocation factors may

be adjusted.

As the Commission has been urged by the Supreme

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