WRT Energy Corp. v. Federal Energy Regulatory Commission

UNITED STATES COURT OF APPEALS
FOR THE FIFTH CIRCUIT

_____________________________

No. 95-60326
_____________________________

WRT ENERGY CORPORATION,

Petitioner,

versus

FEDERAL ENERGY REGULATORY COMMISSION,

Respondent.

_________________________________________________________________

Petition for Review of Order of
Federal Energy Regulatory Commission
_________________________________________________________________

February 28, 1997

Before HIGGINBOTHAM, BARKSDALE and EMILIO M. GARZA, Circuit Judges.

RHESA HAWKINS BARKSDALE, Circuit Judge:

The principal issue at hand is whether natural gas wells,

which previously produced from a gas cap and were subsequently

fitted with new technology for removing gas from the brine in the

aquifer, qualify as producing “high-cost natural gas” pursuant to

the Natural Gas Policy Act, 15 U.S.C. § 3301 et seq.(repealed

1989). Reversing determinations by the Louisiana Department of

Natural Resources, Office of Conservation, the Federal Energy

Regulatory Commission ruled that the gas did not qualify. We

AFFIRM.

I.

WRT Energy Corporation has five wells in Louisiana which

extract brine from an aquifer and then use recently-developed
vortoil hydrocyclones to separate natural gas from the brine.

Prior to installation of this new technology, each well had

produced natural gas by tapping a “cap” of gas which had broken

free from the brine and migrated to the top of the aquifer.

As the gas cap was depleted, however, the pressure in the well

decreased. This pressure reduction allowed gas which had been

dissolved in the brine to resolve out of it; but, it also allowed

the brine which occupied the underlying aquifer to move upward,

replacing all or part of the area previously occupied by the gas

cap. This resulted in fewer well perforations exposed to free gas,

and the well began to produce more and more brine with the gas,

until the well “watered out”. As a result, the wells were going to

be plugged.

WRT’s new process reaches more gas by allowing the production

of gas which never broke free of the brine, but it is more costly

than the usual extraction of natural gas; and, as with any new

application of technology, there is an amount of risk involved.

Accordingly, WRT applied for special treatment of these five wells

under the Natural Gas Policy Act (NGPA).

The purpose of this special treatment is to encourage the

production of natural gas sources, such as geopressured brine,

which would not otherwise be economical to exploit. 1978

U.S.C.C.A.N. 8800, 9003. WRT sought relief under § 107 of the

NGPA, 15 U.S.C. § 3317, which provided an incentive to produce

“high-cost natural gas”. For qualifying gas, the producer could

elect either a pricing benefit under the NGPA, or a tax benefit.

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15 U.S.C. § 3317(d); 26 U.S.C. § 29(c). One way to qualify -- the

route taken by WRT -- is if the gas is “produced from geopressured

brine”. 15 U.S.C. § 3317(c)(2). Because the NGPA was repealed

effective 1 January 1993, the pricing benefits are no longer of

use. Natural Gas Wellhead Decontrol Act of 1989, Pub. L. 101-60,

103 Stat. 157 (1989). But, remaining is the potential tax benefit,

which is not directly at issue in this proceeding, as discussed

infra. 26 U.S.C. § 29(c).

As defined by the FERC, “geopressured brine” is subsurface

fluid that has at least 10,000 parts of dissolved solids for every

million parts water, and has an initial reservoir geopressure

gradient over .465 pounds of pressure per square inch for each

vertical foot of depth. 18 C.F.R. § 272.103. By FERC regulation,

in order for gas to qualify as being “produced from geopressured

brine”, the gas must be “dissolved [in the brine] before initial

production”. 18 C.F.R. § 272.103(c).

Gas exists in brine in two states: (1) in solution--when the

gas is dissolved in the brine; and (2) in free but immobile form--

when the gas has fallen out of solution (or resolved) but remains

trapped in the brine, without migrating to the top to form or join

a gas cap. The NGPA and its regulations make no mention of the

treatment of gas which is not dissolved in the brine, but exists

instead in free immobile form in the brine without rising to form

or join a gas cap. On the other hand, the FERC has expressly

rejected the possibility that gas cap gas could qualify as gas

“produced from geopressured brine”; early on, it required that, in

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order to qualify, the gas had to be dissolved in the brine.

Interim Rules Defining and Deregulating Certain High-cost Natural

Gas, FERC Regulations Preambles 1977-81, 44 Fed. Reg. 61,950 (29

October 1979); Final Rules Defining and Deregulating Certain High-

cost Natural Gas, FERC Regulations Preambles 1977-81, 45 Fed. Reg.

28,092 (28 April 1980).

WRT faced two hurdles in order for the gas to be classified as

being “produced from geopressured brine”: (1) the wells had

previously successfully produced gas cap gas, before “watering

out”; and (2) the brine now being extracted carried natural gas in

two different states: dissolved gas which met the FERC’s definition

as having come from brine, and free immobile gas. Exacerbating

matters is the fact that it is not known with certainty how much of

each type of gas is produced and no one seems to be able to measure

how much of the free immobile gas resolved as a result of the prior

gas cap production.

There is a two-step process for deciding whether natural gas

qualifies as “high-cost”. 15 U.S.C. § 3317(c). First, the

appropriate state or federal agency makes a determination; next,

the FERC makes the conclusive determination, reviewing the earlier

determination for substantial evidence. 15 U.S.C. § 3413(b)(1)(A).

The FERC’s determination is reviewable in a United States Court of

Appeals. 15 U.S.C. § 3413(b)(4)(B).

Consistent with this process, after WRT installed a vortoil

hydrocycone at one of its wells as a test subject, it received a

determination from the Louisiana Office of Conservation (LOC) that

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the well qualified as producing high-cost natural gas. The vortoil

units were then installed at the other four wells; the LOC also

certified them as producing high-cost gas. It found that, although

all the wells had previously produced gas cap gas, the gas now

produced is not from caps, but is either dissolved, or is in free

immobile form, in the brine.

These positive determinations were transmitted to the FERC in

April and May 1994. That August, it issued an adverse notice of

preliminary finding, after requesting and receiving more

information from the LOC and WRT about the wells. This preliminary

finding provided: (1) that the wells would not qualify because

they had previously produced gas cap gas; and (2) that the gas

which was not dissolved in the brine, but instead was in free

immobile form, was not produced “from” the brine.

After the FERC’s preliminary finding, the LOC addressed some

of the FERC’s concerns about the technical and other aspects of the

wells’ production. The FERC held an informal technical conference

and accepted additional post-conference comments.

The FERC’s final order was issued in April 1995. Unlike the

preliminary finding, it reversed the LOC determinations on the sole

ground that the FERC “did not intend to allow any gas in an aquifer

associated with a gas cap to qualify as geopressured brine gas if

gas from the gas cap was produced before significant amounts of

brine [were] produced”. (Emphasis added.) As a result, the FERC

did not reach whether free immobile gas (broken free of the brine

but not part of a gas cap) would qualify as high-cost.

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 II.

In order to determine whether the gas qualifies as high-cost,

we must first consider the prior gas cap production issue. But,

the second issue, whether the free immobile gas qualifies as high-

cost, bears on this first issue. In any event, before reaching the

merits, we will confirm our jurisdiction.

A.

Concerning, inter alia, a high-cost determination,

[a]ny person aggrieved or adversely affected
by a final finding of the [FERC] ... may ...
file a petition for review of such finding....
The reviewing court shall reverse any such
finding of the [FERC] if the State or Federal
agency determination involved is supported by
substantial evidence.

15 U.S.C. § 3413(b)(4)(B). The FERC urged in an earlier motion to

dismiss that, because the NGPA pricing had been repealed, and

therefore the FERC does not control the price at which WRT may sell

its natural gas, any determination by the FERC regarding the status

of the wells has no effect on WRT. And, FERC contended that the

mere possibility that, for tax credit purposes, the IRS will defer

to the FERC in determining whether the gas is produced from

geopressured brine is too conjectural to give standing to WRT.

The motion was denied by another panel of our court. Although

the FERC did not formally raise this issue again, it was noted in

its brief on the merits, citing an opinion rendered after the

motion was denied; and, at oral argument, it urged lack of

standing. In any event, because the issue concerns jurisdiction,

we will, of course, address it.

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 The new case cited by FERC, Marathon Oil Co. v. Federal Energy

Regulatory Commission, 68 F.3d 1376 (D.C. Cir. 1995), is

inapposite. There, the FERC refused to rule on a state agency

determination in that the wells in question were reentered after 1

January 1993, the cutoff date for petitions that the FERC would

review. Id. at 1378. The court held that plaintiffs lacked

standing to challenge the FERC’s refusal to accept (or reject) the

state agency’s determinations. Id. at 1379. No action by the FERC

was exactly that; plaintiffs were not aggrieved, because the FERC

had neither reversed the determination nor remanded the case to the

state agency.

Needless to say, the case at hand presents a far different

scenario; the FERC has made a final determination detrimental to

WRT’s efforts at obtaining a tax benefit. Therefore, we agree with

the earlier panel ruling. In short, the FERC ruled against WRT;

pursuant to 15 U.S.C. § 3413(b)(4)(B), WRT is “aggrieved or

adversely affected”. The FERC ruling is part of this record and

will doubtless play a part in any IRS proceeding. True, it is not

dispositive; the IRS will determine for itself whether the wells

are producing gas from geopressured brine, and it is not bound to

follow the FERC’s ruling. IRS Private Ruling 9035034 (1 June

1990)(FERC determinations “not dispositive” about Section 107

qualification). But, as stated, the FERC ruling will be in play;

WRT will have to counter it. It has standing.

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 B.

As discussed, under the NGPA, the FERC reviews state or

federal agency determinations whether gas qualifies as high-cost

for “substantial evidence in the record upon which such

determination was made”. 15 U.S.C. §§ 3413(a)(1)(D), (b)(1)(A).

The standard for judicial review of FERC final findings is also for

substantial evidence. Id. § 3413(b)(4)(B). Regardless of this

non-deferential standard of review of factual finding, in

promulgating and interpreting its regulations, the FERC has acted,

with Congress’ authorization, to administer and interpret the NGPA.

Id. § 3411. The FERC is due deference in this legal area.

In reviewing an agency’s interpretation of its statute, “if

the intent of Congress is clear, that is the end of the matter ...

[otherwise we ask] whether the agency’s answer is based on a

permissible construction of the statute.” Chevron U.S.A., Inc. v.

Natural Resources Defense Council, Inc., 467 U.S. 837, 843-44

(1984)(emphasis added); see also Pacific Gas Transmission Co. v.

Federal Energy Regulatory Commission, 998 F.2d 1303, 1308 (5th Cir.

1993). Likewise, in reviewing an agency’s interpretation of its

regulations, unless a regulation’s plain language is to the

contrary, we defer to the interpretation of that regulation by the

agency which promulgated it. E.g., Thomas Jefferson University v.

Shalala, 512 U.S. 504 (1994). As discussed infra, such deference

is due the final finding in issue.

As noted, this case concerns two questions: (1) whether wells

which first produced gas cap gas can later qualify as producing

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high-cost gas; and (2) if so, how to factor in the gas coming out

of the brine that is not dissolved and instead is trapped (free

immobile). As explained, although the LOC ruled that neither of

these circumstances were disqualifiers, the FERC reversed, ruling

that, pursuant to the NGPA and its regulations, prior gas cap

production precluded qualification, and that, accordingly, it was

unnecessary to reach “WRT’s request that we clarify whether the

‘immobile’ free gas being produced through the [new technology] is

not gas that has broken free from the brine”. (Such “broken free”

gas arguably would not qualify as high-cost.)

This much is certain: the NGPA is a complex statute, one that

was designed to control natural gas pricing and yet allow

sufficient flexibility so that prices would encourage the

production of gas that is more difficult to produce. See, e.g.,

Preamble to Final Rules, FERC 1977-81, 45 Fed. Reg. 28,093. The

Act concerned, among other things, pricing for new and high-cost

natural gas. 15 U.S.C. §§ 3312, 3317. There are numerous

corresponding terms, definitions and contingencies. E.g., id. §§

3301 (“Definitions”), 3316 (“Ceiling price for sales under rollover

contracts”).

To this end, the FERC is given quite a bit of discretion. For

example, for the first sale of high-cost natural gas, the FERC

could set a price above “the otherwise applicable maximum lawful

price to the extent that such special price is necessary to provide

reasonable incentives for the production of such ... gas.” Id. §

3317(b). Furthermore, the FERC is expressly authorized to perform

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“any and all acts” and to “issue, amend and rescind” any rules

necessary for the enforcement of the NGPA. Id. § 3411(a). This

expressly includes the authority to define any technical and trade

terms used in the NGPA. Id. § 3411(b).

Obviously pertinent to whether wells which previously produced

gas cap gas can qualify as high-cost is the fact that the NGPA

enumerated four methods for producing gas that might qualify as

high-cost:

(1) produced from any well the surface
drilling of which began on or after February
19, 1977, if such production is from a
completion location which is located at a
depth of more than 15,000 feet;

(2) produced from geopressured brine;

(3) occluded natural gas produced from coal seams;

(4) produced from Devonian shale....

15 U.S.C. § 3317(c)(1)-(4). Each of these types involves higher

cost to produce than usual gas production. Moreover, this section

contains a fifth “catch-all” category; the FERC could determine

that a well presented “extraordinary risks or costs”. Id. §

3317(c)(5).

And, this section on high-cost gas contained another

qualifier: “the term ‘high-cost natural gas’ means natural gas

determined in accordance with section 3413" which was produced

under one of the five above described methods. Id. § 3317(c)

(emphasis added). Section 3413, as previously discussed, provides

for the initial state or federal agency finding, followed by FERC,

and possible judicial, review. This is yet another instance of

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discretion being placed with the FERC for interpreting this

section.

Certainly, § 107 of the NGPA, 15 U.S.C. § 3317, does not

provide expressly that gas can qualify as high-cost only if it is

produced, unlike here, by a “new well”. And, the NGPA deals

extensively with production from a “new well”, defined as one for

which

(A) The surface drilling ... began on or
after February 19, 1977; or

(B) the depth ... was increased, by means of
drilling on or after February 19, 1977, to a
completion location which is located at least
1,000 feet below the depth of the deepest
completion location of such well attained
before February 19, 1977.

15 U.S.C. § 3301(3). In fact, one of the four listed methods for

possibly qualifying as high-cost is through a certain type of new

well -- one for which “surface drilling began on or after February

19, 1977, if such production is from a completion location which is

located at a depth of more than 15,000 feet”. This type of “new

well” has a different, probably more costly, production depth than

for other “new wells”. Therefore, it can be maintained quite

persuasively that, because 15 U.S.C. § 3317 does not mention a “new

well” in conjunction with gas “produced from geopressed brine”,

such gas need not be from a “new well” in order to qualify.

But, this section, 15 U.S.C. § 3317, cannot be read in

isolation; it must be read in the light of the NGPA as a whole.

See, e.g., Medtronic, Inc. v. Lohr, ___ U.S. ___, 116 S. Ct. 2240

(1996). When read as a whole, the complexity of the NGPA, as well

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as the earlier discussed discretion vested with the FERC by 15

U.S.C. § 3317, precludes reading § 3317 as providing the complete

answer to the post-gas cap production question at hand.

Accordingly, we must look to the FERC’s interpretation of the

section.

The apparent intent of Congress, as discussed by the FERC for

its final finding, was to reward producers who incurred, “the high-

costs of brine disposal from the start”, and to grant the FERC a

great deal of authority over the way in which the incentives are

implemented. In fact, as discussed infra, the FERC noted in its

final finding that the NGPA and its regulations have never been

read to intend to reward a producer for a well, all or part of the

cost of which had been recouped by producing from a gas cap, and

which later produces, as an added bonus, the gas both dissolved and

trapped (free immobile) in the brine.

As noted, the regulations define “produced from geopressured

brine” as

natural gas which is dissolved before initial
production of the natural gas in subsurface
brine aquifers with at least 10,000 parts of
dissolved solids per million parts of water
and with an initial reservoir geopressure
gradient in excess of .465 pounds per square
inch for each vertical foot of depth.

18 C.F.R. § 272.103(c) (emphasis added). Furthermore, the question

at hand was touched on by the FERC in the preamble to its interim

regulations:

Gas not dissolved in brine, such as gas caps,
may be economically produced through less
expensive conventional production techniques
and is not a high-cost gas. Therefore, if the

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 gas has broken free from the brine before
initial production (before any fluids are
withdrawn from the reservoir), it will not
qualify under this definition.

44 Fed. Reg. 61,950 (emphasis added). In the preamble to the final

regulations, the FERC did not alter this position, stating in

relevant part that “qualification under this category of gas

relates only to whether the gas is dissolved gas produced from

geopressured brine”; and that

[i]n the interim regulations the Commission
considered the possibility of qualifying “free
gas” caps found in association with brine.
For the same reasons elucidated therein, the
Commission will not include such free gas in
its definition of “natural gas produced from
geopressured brine.”

FERC 1977-1981, 45 Fed. Reg. 28,093.

As noted, portions of the gas in issue are dissolved in the

brine, but other portions are free, yet immobile. This finding is

not challenged by WRT, and is supported by substantial evidence.

Restated, it is undisputed that all of the gas is not dissolved in

the brine. The above quoted interim rules’ preamble merely lists

gas cap gas as one example of gas (“such as gas caps”) which can be

produced in association with brine, but which is not dissolved in

it.

The regulation provides that “‘natural gas produced from

geopressured brine’ is natural gas which is dissolved before

initial production”. 18 C.F.R. § 272.103(c). In conjunction with

this, the interim rules’ preamble’s definition of “initial

production” is of assistance: “before any fluids are withdrawn from

the reservoir”. This seems to preclude post-gas cap production,

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because fluids (brine) would probably, if not certainly, be

withdrawn during gas cap production, as the brine moved upward

because of the resulting pressure reduction caused by removal of

gas from the gas cap. But, there may be ambiguity in the interim

rules’ preamble’s statement that, if the gas has “broken free”, it

will not qualify. There is no definition for when the gas has

“broken free”: when it resolves out of the brine and becomes free

immobile gas, or when it actually escapes the brine and forms or

joins a gas cap. In the light of such questions, we defer to the

promulgating agency. For example, as quoted earlier from the

preamble to the final rules, and consistent with the regulation,

“qualification under this category of gas relates only to whether

the gas is dissolved gas produced from geopressured brine”.

Based on the NGPA, the FERC’s arguments here, and its

admission that the new technology was not available and therefore

not considered during its rule making, there is reason to believe

that it had not fully considered the question of free immobile gas.

But, in the face of the clear statement in the regulation that, in

order to qualify as high-cost, the gas must be “dissolved before

initial production”, we must apply it as written. Therefore, we

rely on this plain language that the gas must be dissolved in the

brine in order to qualify as coming “from” the brine.

In conjunction with this, the FERC contends that once some of

the gas produced has been shown not to be “from geopressured

brine”, all of the gas must be disqualified, regardless of how much

was in fact dissolved in the brine. This maintains the NGPA’s

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basic approach of regulating wells, not gas molecules. See e.g.,

15 U.S.C. 3317(a)(regulating gas “produced from any well”)(emphasis

added). Moreover, this requirement finds substantial support in the

record. It avoids the impossible task, as stated in the FERC’s

final order, of “trying to distinguish free gas molecules from

dissolved gas molecules”. This task would be made even more

difficult under the circumstances presented here, because, as

noted, the regulation provides that the gas must be dissolved at

the time of initial production. 18 C.F.R. § 272.103(c). As also

discussed, “initial production” is defined in the interim rules’

preamble as “before any fluids are withdrawn from the reservoir”.

Therefore, where there has been, as here, production from the gas

cap, then that is the “initial production”.

Along this line, the private study of the wells at issue

placed the percentage of dissolved gas being produced at 1.4%

volumetrically, but placed the production of free immobile gas at

between 1 and 7% of volume of brine production. This disparity

between dissolved gas and free immobile gas indicates that the

ruling which WRT seeks would not have the profound effect on its

gas production which it claims is needed in order to make the

production cost-effective. In other words, there is little evidence

that a favorable ruling in this instance as to the dissolved gas

would affect the well costs significantly.

Another, earlier noted, factor in the record which provides

compelling support for the FERC’s ruling is that, according to the

FERC, the LOC determination in issue is the first finding that

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post-gas cap production qualifies as high-cost. In its final

order, the FERC stated that,

[w]hile the preambles to the Interim and Final
Rules did not specifically so state, the
[FERC] intended, and it is the [FERC’s]
understanding the jurisdictional agencies and
producers in general interpreted the
regulations to mean, that if gas was produced
from a gas cap before the onset of fluids
production from the underlying aquifer, none
of the gas subsequently produced from the gas
cap and/other underlying aquifer could qualify
under the [FERC’s] regulations. Thus, under
this interpretation, gas produced through
secondary recovery operations was precluded
from qualifying as geopressured brine gas.

As a result, according to the FERC, “[it] received no affirmative

geopressured brine gas determinations between 1979, when [its]

Interim Rule was adopted, and 1994, when Louisiana’s affirmative

determinations for WRT’s wells were received.” Therefore, as

quoted supra, the FERC “affirm[ed] that it did not intend to allow

any gas in an aquifer to qualify as geopressured brine gas if gas

cap gas was produced before significant amounts of brine [were]

produced.” (Emphasis added.)

This reading by the FERC takes into consideration a number of

factors bearing on the production of natural gas, including hydro-

geological and other pertinent data about aquifers, economic

efficiency, and wellhead technology. Needless to say, the FERC is

far better able than we to evaluate such factors; this is one of

the reasons why it is entitled to deference under the NGPA. In

sum, we defer to its conclusion that

Congress deregulated gas produced from
geopressured brine to provide an incentive for
drilling wells into previously unproduced

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 geopressured aquifers to tap gas dissolved in
brine, not for producing gas from partially
depleted or nearly depleted gas reservoirs.

In the light of this conclusion, which is consistent with both the

NGPA and its regulations, and is within the discretion of the FERC,

we affirm its ruling that the wells in issue, which previously

produced gas cap gas, do not qualify as high-cost natural gas

producers.

WRT contends that the FERC’s final finding, if upheld, is

impermissibly retroactive. We recognize that this is the first

time the FERC has squarely addressed these issues, and it comes

years after the NGPA was repealed. But, WRT does not challenge the

FERC’s making a final finding. Although the NGPA was repealed in

pertinent part by the Wellhead Decontrol Act, the FERC continued to

make determinations regarding high-cost status through the date of

its rule rescinding Part 275 of its NGPA regulations, 28 July 1994.

The FERC received the LOC’s determinations in this case in April

and May 1994, before the effective date of the rescission. 59 Fed.

Reg. 40,240 (28 July 1994).

Concerning this retroactive-rule-making contention, we note

that WRT apparently relied, perhaps imprudently, on the affirmative

LOC determination as to the first well when it subsequently

installed the new technology on its other four wells, prior to

receiving a final determination from the FERC as to that first

well. In any event, the fact that the final determination followed

repeal of the NGPA and installation of the new technology does not

render it retroactive. Moreover, as noted, long before the new

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technology was installed and production resumed, the FERC had

spoken -- certainly in part -- to the issues at hand. 18 C.F.R. §

272.103(c); 44 Fed. Reg. 61,950. The application of the language

from the regulations and preambles, and indeed from the statute

itself, to this record cannot be said to be retroactive.

III.

For the foregoing reasons, the final finding of the Federal

Energy Regulatory Commission is

AFFIRMED.

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