Court Opinion

ID: 3008435
Source: CourtListenerOpinion
Date Created: 2015-10-07 19:52:27.764488+00
Date Added: 2024-06-11T11:46:12.455720
License: Public Domain

IN THE SUPREME COURT OF TEXAS

IN THE SUPREME COURT OF TEXAS
 
════════════
No. 03-0824 
════════════
 
Kathryn Aylor Bowden, Beulah Poorman Vick, 
Omer F. Poorman, Monte Cluck, Royce Yarbrough, and 
Benny Ted Powell, Petitioners,
 
v.
 
Phillips Petroleum Company, 
GPM Gas Corporation, Phillips Gas Marketing Company, Phillips Gas Company, and 
GPM Gas Trading Company, Respondents
 
════════════════════════════════════════════════════
On Petition for Review from the
Court of Appeals for the Fourteenth District of 
Texas
════════════════════════════════════════════════════
 
 
Argued December 1, 
2004
 
 
            
Justice Wainwright delivered the opinion of the 
Court.
 
            
Justice Brister did not participate in this 
decision.
 
            
This is an interlocutory appeal challenging the certification of a class 
of oil and gas royalty owners under former rule 42(b)(4) of the Texas Rules of Civil Procedure.[1] The royalty owner class 
representatives—Kathryn Aylor Bowden, Beulah Poorman Vick, Omer F. Poorman, 
Royce Yarbrough, Benny Ted Powell, and Monte Cluck—allege that Phillips 
Petroleum Company underpaid royalties due under oil and gas production leases 
through its inter-affiliate transactions. The trial court certified three 
subclasses of royalty owners for breach of lease claims against Phillips and its 
subsidiaries and affiliates: GPM Gas Corporation, Phillips Gas Marketing 
Company, Phillips Gas Company, and GPM Gas Trading Company (collectively, 
Phillips). Phillips brought an interlocutory appeal challenging the class 
certification order. The court of appeals held that the trial court abused its 
discretion in certifying the three subclasses because each subclass failed to 
meet several requirements for certification under Rule 42. 108 S.W.3d 385. The 
court of appeals held the class representatives impermissibly failed to assert 
all claims for damages under the leases and the unasserted claims would be 
barred from subsequent litigation by res judicata. 
Id. at 
402–04. The court of appeals also held that individual issues of liability would 
predominate over common issues for all three subclasses, and that the class 
representatives for Subclasses 2 and 3 were inadequate. Id. at 396–403. We 
affirm on different grounds the court of appeals’ judgment decertifying 
Subclasses 1 and 3, but reverse the judgment decertifying Subclass 2, and remand 
the case for further proceedings consistent with this opinion.
 
I. FACTUAL AND 
PROCEDURAL BACKGROUND
 
            
This is an appeal of the second attempt to certify the claims of three 
subclasses of royalty owners against Phillips. See Phillips Petroleum Co. v. 
Bowden, No. 14-00-01184-CV, 2001 Tex. App. 
LEXIS 7027 (Tex. App.—Houston [14th Dist.] Oct. 
18, 2001, no pet.) (not designated for publication) (Bowden I). The class 
members are Texas royalty owners who leased their property 
to Phillips for oil and gas production. They allege Phillips underpaid royalties 
due under the leases through self-dealing transactions.
            
In September 2000, the trial court signed its first order certifying 
three subclasses and shortly thereafter signed a trial plan pursuant to our 
holding in Southwest Refining Co. v. Bernal, 22 S.W.3d 425 (Tex. 2000). 
Subclass 1 royalty owners alleged Phillips breached an implied covenant to 
market under the leases. Subclass 2 royalty owners alleged Phillips breached 
their Gas Royalty Agreements (GRAs) by paying 
royalties based on the dry residue gas component of natural gas petroleum but 
not on the liquid components of the gas produced, and by using a measurement 
system which failed to include the heat content of the gas. Subclass 3 royalty 
owners alleged Phillips breached the implied covenant to market by assessing an 
unreasonably high service fee to its marketing affiliate through percentage of 
the proceeds (POP) contracts, thereby reducing income to the royalty owners.
            
In Phillips’ first interlocutory appeal, the court of appeals reversed 
the certification order and remanded the case to the trial court to resolve 
deficiencies in the class action certification. Bowden I, 2001 Tex. App. LEXIS 7027, at 
*2–3. The deficiencies of Subclasses 1 and 3 related to changes in oil and gas 
law. While Bowden I was pending in the court of appeals, we held in Yzaguirre v. KCS Resources, Inc. that there is 
no implied covenant to market oil and gas for royalty owners paid under express 
market value royalty provisions. 53 S.W.3d 368, 373–74 (Tex. 2001). Thus, the 
court of appeals reasoned that only some royalty owners in Subclasses 1 and 3 
were entitled to royalties under an amount-realized or proceeds basis with an 
implied covenant to market. Bowden I, 2001 Tex. App. LEXIS 7027, at 
*15–16. The court of appeals then held that this distinction among royalty 
owners undermined typicality for Subclasses 1 and 3. Id. at *16–17. For 
Subclass 2, the court of appeals held the trial court abused its discretion by 
finding that class representative Monte Cluck satisfied the typicality and 
adequacy of representation requirements because there was no evidence in the 
record that Cluck’s GRA was substantially similar to the GRAs of Subclass 2 members. Id. at *17–21.
            
On remand, the royalty owners filed an amended motion for class 
certification and attempted to address the court of appeals’ concerns. In June 
2002, the trial court granted class certification after a second hearing, 
certifying the following three subclasses:
 
Subclass 
1: Royalty owners who own or owned royalty interests under leases located in the 
state of Texas; where Phillips Petroleum Company is the lessee; under the terms 
of the lease, the payment of royalty of natural gas production is based on 
proceeds or amount realized; from which Phillips Petroleum produced natural gas 
(including natural gas liquids) that was directly sold or indirectly sold or 
transferred to Phillips Gas Marketing for marketing or resale; and during the 
period February 1995 through the present.
 
Subclass 
2: Royalty owners who own or owned royalty interests under leases located in the 
state of Texas; where Phillips Petroleum Company is the lessee; the royalty is 
paid pursuant to a Gas Royalty Agreement containing language substantially 
identical to the language bracketed in the Gas Royalty Agreement attached as 
Exhibit 1 and incorporated herein by reference; the Gas Royalty Agreement has no 
additional language relating to processing gas or the payment of royalty on 
natural gas liquids; and during the period February 1995 through the 
present.
 
Subclass 
3: Royalty owners who own or owned royalty interests under leases located in the 
Panhandle of the state of Texas; where Phillips Petroleum Company is the lessee; 
the leases provide for payment of royalties on natural gas production on an 
amount realized/proceeds basis or market value/market price basis; from which 
Phillips Petroleum produced natural gas (including natural gas liquids) that was 
directly or indirectly sold or transferred to GPM (or any successor entity) for 
marketing or resale; Phillips Petroleum Company was paid on the basis of a gas 
purchase contract between Phillips and GPM (or any successor entity); and during 
the period February 1995 through the present.
 
 
The revised 
Subclass 1 only includes claims from royalty owners paid on an amount-realized 
or proceeds basis and who assert claims for breach of an implied covenant or 
express covenant to market. In the revised Subclass 2, Royce Yarbrough and Ted 
Powell were substituted as representatives in lieu of Cluck. The revised 
Subclass 3 now includes a claim that Phillips breached the implied covenant to 
manage and administer the lease by entering into POP contracts with one of its 
marketing affiliates, paying it an unreasonably high fee to process the gas. 
Although all three subclasses involve lease agreements, the class 
representatives, on behalf of the royalty owners, did not assert all claims 
involving the lease agreements at issue, choosing to assert only those claims 
they believed likely to meet the predominance requirement of Rule 42(b)(3). The 
second certification order excluded the claims the class representatives decided 
not to pursue, stating “this class does not include claims by class members that 
are not based on the foregoing class claims.”
            
Phillips filed a second interlocutory appeal challenging the second class 
certification order. The court of appeals reversed and remanded the 
certification order. 108 S.W.3d at 404. We granted the royalty owners’ petition 
for review.
 
II. JURISDICTION 
AND STANDARD OF REVIEW
 
            
This Court has jurisdiction to review an interlocutory appeal of an order 
certifying or denying certification of a class action without regard to whether 
a conflict exists between courts of appeals. Tex. Civ. Prac. & Rem. Code § 
51.014(a)(3); Tex. Gov’t Code § 
22.225(d).
            
We review a class certification order for abuse of discretion. Compaq 
Computer Corp. v. Lapray, 135 S.W.3d 657, 671 
(Tex. 2004). A 
trial court abuses its discretion if it acts arbitrarily, unreasonably, or 
without reference to any guiding principles. Walker v. Packer, 827 S.W.2d 833, 839 (Tex. 1992). We do not, 
however, indulge every presumption in the trial court’s favor, as compliance 
with class action requirements must be demonstrated rather than presumed. 
Henry Schein, Inc. v. Stromboe, 102
S.W.3d 675, 691 (Tex. 2002). Although a trial court generally 
has broad discretion to determine whether to certify a class action, it must 
apply a rigorous analysis to determine whether all certification requirements 
have been satisfied. Compaq, 135 S.W.3d at 663; 
Bernal, 22 S.W.3d at 435.
 
III. RES 
JUDICATA
 
            
The class representatives argue the court of appeals erred in concluding 
they “must bring all claims relating to the breach of the lease agreements in 
the same action or they will be subject to res judicata’s preclusive effect.” 108 S.W.3d at 403. In their 
motion to certify, the class representatives strategically chose not to assert 
all claims arising from the oil and gas leases and GRAs. The class representatives alleged a single breach of 
contract claim on behalf of each respective subclass rather than including the 
various implied or express obligations under the leases and agreements in the 
suit. The court of appeals, agreeing with Phillips, held the certification order 
impermissibly split the class members’ causes of action, suggesting such 
splitting of claims was inappropriate under Rule 42(d). Id. at 404. 
Rejecting other courts of appeals’ decisions, the court of appeals held the 
unasserted claims were subject to res judicata’s 
preclusive effect and that the class representatives’ willingness to abandon 
those claims rendered them inadequate representatives. Id.
            
The class representatives argue their abandoned claims may not be 
precluded in future litigation, even under the transactional approach to res 
judicata. They agree the transactional approach 
precludes the relitigation of those claims that could 
have or should have been asserted in prior litigation, but contend that res 
judicata should not preclude those claims which are 
not subject to classwide treatment. Citing our holding 
in Amstadt v. United States Brass Corp., 
the class representatives argue the unasserted claims do not meet the three 
prerequisites for barring claims by res judicata: “1) 
a prior final judgment on the merits by a court of competent jurisdiction; 2) 
identity of parties or those in privity with them; and 
3) a second action based on the same claims as were raised or could have been 
raised in the first action.” 919 S.W.2d 644, 652 (Tex. 1996). Specifically 
the class representatives argue such claims cannot be certified in a class 
action and, therefore, are not subject to claim preclusion in future 
litigation.
            
As we held in Citizens Insurance Co. v. Daccach, to apply res judicata 
to class actions in this manner would produce inconsistent results between class 
actions and other forms of litigation. 217 S.W.3d 430, 451 (Tex. 2007). Class 
suits remain subject to the same claim preclusion rules as other procedural 
forms of litigation. Id.; see also Bernal, 22 S.W.3d at 432 
(holding class actions are subject to the same punitive damages rules as other 
forms of litigation). Applying Texas’s transactional approach to res judicata, class members will be barred only from asserting 
claims in subsequent individual litigation which arose from the same transaction 
or subject matter and either could have been or were litigated in the prior 
suit. Daccach, 217 S.W.3d at 450, 
455 (citing Barr v. Resolution Trust Corp., 837 S.W.2d 627, 631 
(Tex. 1992)).
            
We disagree with the court of appeals’ 
holding that class representatives who split the claims of the class are per se 
inadequate. 108 S.W.3d at 404. As for the application of res judicata to class suits, we crossed this bridge in Daccach. 217 S.W.3d at 457. Courts do not dictate the 
strategies parties must follow in litigation nor do they instruct litigants 
which claims or defenses they should, or should not, bring. As in other legal 
actions, however, class litigants are subject to the consequences of their 
choices and the doctrine of claim preclusion may bar future litigation of claims 
that they decide not to pursue in the current suit. Daccach, 217 S.W.3d at 451. If the class 
representatives do not assert at the trial court all claims for damages arising 
from the leases which could have been litigated before the trial court, the 
unasserted claims may be precluded by res judicata in 
subsequent litigation. Id. The tactical and strategic decisions to 
structure the lawsuit are theirs; the implications of their actions are 
established by law.
            
The court of appeals summarily concluded the “willingness of the class 
representatives to abandon claims for the sake of achieving commonality” means 
the representatives cannot adequately represent the class, and thus the trial 
court abused its discretion in certifying the class. 108 S.W.3d at 404. Under 
that approach, class representatives would always risk being inadequate 
representatives if they did not assert all possible claims for each individual 
class member. At the same time, though, class representatives bringing excessive 
numbers of individual claims may burden their ability to satisfy the typicality 
and predominance requirements.
            
We previously explained that a class representative’s decision to assert 
certain claims and abandon others affects the certification determination. The 
choice of claims to pursue or abandon is one relevant factor in evaluating the 
requirements for class certification such as typicality, superiority, and 
adequacy of representation. Daccach, 217 S.W.3d 
at 448. A proper analysis requires the trial court to venture beyond the 
pleadings and to “‘understand the claims, defenses, relevant facts, and 
applicable substantive law in order to make a meaningful determination of the 
certification issues.’” Bernal, 22 S.W.3d at 435 (quoting Castano v. Am. Tobacco Co., 84 F.3d 734, 744 
(5th Cir. 1996)). Trial courts should assess the Rule 42 requirements in light 
of res judicata’s preclusive effect on abandoned 
claims when considering whether to certify a class.
            
In the second certification order, the trial court acknowledged that the 
class limited its suit to a single claim for each subclass. On remand, it should 
consider the applicability of res judicata in future 
proceedings to abandoned claims in evaluating certifiability, as we explain in Daccach, as part of its determination of the 
prerequisites of commonality, typicality, superiority, adequacy of 
representation, and predominance. Tex. 
R. Civ. P. 42(a),(b). 
 
IV. SUBCLASSES
 
            
The substance of the class claims, and in turn their certifiability, depends on the royalty agreements the class 
entered into with Phillips over sixty years ago. The 1940s was a different era 
in the oil and gas industry. It was not uncommon at the time for natural gas to 
be viewed as a potentially dangerous complication or bothersome waste product in 
the production of valuable oil. See Bruce M. Kramer, Interpreting the 
Royalty Obligation by Looking at the Express Language: What a Novel Idea?, 
35 Tex. Tech L. Rev. 223, 231–32 
(2004). Consequently, oil and gas leases traditionally have included 
little guidance on the methods for measuring gas production for royalty 
calculations. Id.
            
The federal government began to regulate natural gas prices in 1954 and 
later, in 1978, gas pricing was deregulated, as it is now. William F. Fox, Jr., 
Transforming an Industry by Agency Rulemaking: Regulation of Natural Gas by 
the Federal Energy Regulatory Commission, 23 Land & Water L. Rev. 113, 114 
(1988). Adding to these regulatory changes, the revolution in technology that 
allows real-time trading of commodities, and with pipelines no longer purchasing 
gas but charging to transport it, gas is now being “marketed in ways never 
imagined when most leases and their [royalty] provisions” were drafted. Dick 
Watt et al., Royalty Litigation—Key Issues: Part I, 19-1 Texas Oil and Gas Law Journal 1, 4 
(2005). Although the dispute in this lawsuit arose in modern times, we 
interpret the obligations and rights of the parties according to their expressed 
intent when they entered the agreement. Fortis Benefits v. Cantu, 234
S.W.3d 642, 647 (Tex. 2007); Lenape Res. Corp. v. 
Tenn. Gas Pipeline Co., 925 S.W.2d 565, 574 (Tex. 1996) (“In construing a 
written contract, our primary concern is to ascertain the true intentions of the 
parties expressed in the written instrument.”).
A. Subclass 1
            
Subclass 1 is comprised of royalty owners who have natural gas leases 
with Phillips, which in turn produces natural gas and sells it to its affiliate 
Phillips Gas Marketing Company (PGM). Specifically, this subclass only includes 
royalty owners with gas royalty clauses requiring Phillips to calculate the 
royalty as a percentage of the proceeds Phillips receives for selling the gas. 
“Proceeds” or “amount realized” clauses require measurement of the royalty based 
on the amount the lessee in fact receives under its sales contract for the gas. 
Union Pac. Res. Group v. Hankins, 111 S.W.3d 69, 72 (Tex. 2003) 
(citing Yzaguirre, 53 S.W.3d at 372). By 
contrast, a “market value” or “market price” clause requires payment of 
royalties based on the prevailing market price for gas in the vicinity at the 
time of sale, irrespective of the actual sale price. Yzaguirre, 53 S.W.3d at 372. The market price may or 
may not be reflective of the price the operator actually obtains for the gas. 
Id. at 372–73.
            
Subclass 1 consists primarily of royalty owners in Fort Bend and Brazoria 
counties where Phillips sells gas to PGM. According to the royalty owners, there 
are approximately 2,330 oil and gas leases in Fort Bend County and 538 leases in 
Brazoria County eligible for membership in Subclass 1. These leases are not all 
identical. Some of the leases, including leases for the named representatives, 
contain gas royalty clauses providing for an amount-realized basis if the gas is 
sold at the well by Phillips and a market-value basis if Phillips sells or 
consumes the gas off the premises or uses the gas to manufacture 
gasoline.[2] This provision 
is called a “two-pronged” clause and provides different methods for calculating 
gas royalties for the same well depending on the circumstances of the sale. 
Additionally, many of the leases, including the named representatives’ leases 
for Subclass 1, have a separate express clause requiring Phillips to exercise 
reasonable diligence to market the gas it produces.[3]
            
Although the leases contain different royalty clauses, including some 
express duty to market provisions, the royalty owners argue there is a common 
question for Subclass 1: whether Phillips failed to reasonably market the gas. 
Specifically, they argue Phillips failed to act as a reasonably prudent operator 
when it entered into a gas purchase agreement with its wholly-owned affiliate 
PGM.[4] The royalty 
owners allege Phillips, by selling gas at a lower price to PGM, failed to 
diligently market and achieve the higher price it received or could receive for 
arms-length transactions to third parties. In other words, they claim Phillips 
paid the subclass royalties based on gas sales to its affiliate PGM rather than 
paying higher royalties based on higher sales prices for gas it could sell in an 
arms-length transaction with a non-affiliate. The royalty owners claim that PGM 
earned higher profits at its expense and Phillips paid lower royalties by 
bringing its affiliate into the transaction.
            
The court of appeals held that individual issues regarding duty and 
breach predominated over the common issues for Subclass 1. 108 S.W.3d at 396. 
The predominance requirement is intended to preclude class action litigation 
when the sheer complexity and diversity of the individual issues would overwhelm 
or confuse a jury. Schein, 102 S.W.3d at 690; Bernal, 22 S.W.3d at 
434. First, the court of appeals reasoned that because only leases paying 
royalties on an amount-realized or proceeds basis, rather than a market-value basis, are 
included in Subclass 1, a jury would need to determine the point of sale for gas 
from each well in the subclass to ascertain which method of calculating 
royalties in the two-pronged clauses applied. 108 S.W.3d at 396. The court of 
appeals held these individual determinations for each well would prevent the 
class from satisfying the predominance requirement. Id. The royalty 
owners argue that because Phillips has computer records containing detailed 
information on each lease agreement and the point of sale for each well, a jury 
will not need to determine class membership based on the variety of sales 
factors. Phillips’ database, they assert, could identify the points of sale for 
each well and calculate the sale price and royalty for each royalty owner’s 
well. 
            
Phillips produces natural gas from the wells and sells that gas at or 
near the wells to PGM. PGM then gathers the gas from the points of sale, 
processes the gas, and sells it under contract to the City of Garland, Texas, 
and to Phillips’ refinery near Sweeney, Texas. Some of the gas is sold after 
processing into the Texas intrastate pipeline system. It may be, then, that all 
the leases in Subclass 1 would qualify as “proceeds” leases. Even assuming, 
however, that all Subclass 1 class members have “proceeds” leases, or that 
Phillips’ database can be easily used to identify those royalty owners that do, 
that assumption does not by itself qualify the subclass for certification. There 
are other conditions necessary for certification of the subclass.
            
The royalty owners argue that in Union Pacific Resource Group, Inc. v. 
Hankins, this Court confirmed that a class of royalty owners consisting 
solely of proceeds leaseholders is properly certifiable, focusing on our 
statement that there was a common legal question as to whether the proceeds 
actually received by the lessee were a fraud or a sham. 111 S.W.3d at 70. 
Arguing that this case is similar to Hankins on both the law and the 
facts, the royalty owners conclude our holding in Hankins means we should 
reverse the court of appeals’ holding that Subclass 1 failed 
predominance.
            
Hankins did not establish that a class of proceeds leaseholders is 
always certifiable. While Hankins did involve similar allegations that 
the lessee’s intra-affiliate sale transactions were a sham, the issue before the 
Court was whether there was a common legal
question within a class consisting of market 
value and proceeds leases. Id. We rejected the contention that market 
value and proceeds leases both required a lessee to obtain the best price 
reasonably attainable and decertified the Hankins class because it failed 
to meet the Rule 42 commonality requirement. Id. at 74–75. While 
Hankins suggests class certification of a proceeds-only class is 
possible, it did not certify such a class, and did not further consider other 
certification prerequisites. See id. Accordingly, Hankins does not 
compel certification of this subclass.
            
Turning to the predominance issue, the court of appeals also held that 
Phillips would owe each royalty owner a different duty to market depending on 
the terms of the lease due to the existence of express provisions in some of the 
leases on the duty to market. 108 S.W.3d at 395. There is no implied covenant if 
a lease contains an express covenant on the same subject matter. Yzaguirre, 53 S.W.3d at 373. Implied covenants in oil 
and gas law protect against lessee self-dealing and negligence, and they are 
unnecessary where the parties have expressly agreed on the duties owed in 
writing. Id. at 374. For leases with an express clause, Phillips’ duty 
would be determined by that clause rather than an implied covenant to market as 
a reasonably prudent operator. Of the nearly 3,000 leases, some contain express 
clauses and some do not, and many of the express clauses contain different 
language. For these reasons, the court of appeals concluded individual issues 
would predominate, and the trial court had abused its discretion in certifying 
Subclass 1. 108 S.W.3d at 396.
            
The royalty owners rely on Hankins and Yzaguirre for their position that a covenant 
to market is implied in all proceeds leases and, therefore, there is a common 
question of whether Phillips breached its duty to market for all royalty owners 
with proceeds-based leases. Neither Hankins nor Yzaguirre, however, suggest the duty to market is 
implied in all proceeds leases. In both cases we concluded that a duty to market 
can be implied in a proceeds lease and not in a market value lease, but this 
does not mean there is an implied duty in all proceeds leases. In fact, we held 
in Yzaguirre that there is no implied covenant 
when the oil and gas lease expressly addresses the subject matter of an asserted 
implied covenant. Yzaguirre, 53 S.W.3d at 373. 
Thus, for the proceeds-based leases in Subclass 1 that contain an express 
covenant requiring a duty to market, there is no implied duty to market. The 
royalty owners’ assertions to the contrary misread our holdings in 
Hankins and Yzaguirre. Certainly 
Phillips owes a duty to market to the members of Subclass 1, but it owes each 
royalty owner either an express or an implied duty, not both. 
            
The court of appeals emphasizes the differences among the leases and 
concludes there is no common liability question discernible without examining 
each lease—particularly because those leases with express clauses would require 
a different duty than the implied duty to market. 108 S.W.3d at 395–96. While 
this is a possibility, it is not clear from the record that any of the express 
duty to market clauses would in practice require different conduct from the duty 
in the implied covenant to market. However, for different reasons than the court 
of appeals, we agree that Subclass 1 has not met Rule 42’s predominance 
requirement.
            
Even if we were to assume that Phillips owes identical duties to market 
to all of the Subclass 1 royalty owners, whether under an express or implied 
duty, the task for the jury would be to determine the price a reasonably prudent 
operator would have received at the wellhead. In this case, the variations in 
well locations, quality of production, and field regulations, among other 
factors, will require the jury to conduct a well-by-well analysis, defeating 
predominance unless the class offers particular evidence that the gas price at 
the wells can be evaluated classwide.
            
In an attempt to show such classwide evidence 
of Phillips’ breach, the royalty owners point to the higher prices obtained by 
PGM in sales to third parties off the premises as compared to the prices 
Phillips charges PGM at the wellhead. Following the sale from Phillips, however, 
PGM gathers gas from the wells and sells it under contracts with delivery points 
miles away from the wells. The higher prices obtained by PGM from the sale of 
gas to the third parties include post-production costs that would not be 
incurred in sales at the wellhead. The royalty owners did not produce 
classwide evidence that would account for variations 
in post-production charges, such as transportation charges or other service 
charges, between each particular well and point of delivery. Although it 
might be possible under certain circumstances to show that a lessee failed to 
diligently market the gas and obtain a reasonable price for a class of lessors, the royalty owners in this case have not provided 
classwide evidence of these alleged 
deficiencies.[5] Because 
individual issues would predominate, the trial court abused its discretion in 
certifying the class. For this reason, we affirm the court of appeals’ judgment 
as to Subclass 1.
B. Subclass 2
            
Subclass 2 is comprised of royalty owners whose royalties are calculated 
under uniform language in Gas Royalty Agreements (GRAs). The GRAs provide that the 
lessee, Phillips, shall pay a royalty on all gas, other than casinghead gas, produced from the leases and “sold or used 
off the premises.” The royalty is determined as follows:
  
The royalty on the total volume of sweet gas so produced 
and so sold or used shall never be less than four cents (4c) multiplied by 
one-eighth (1/8) of the total volume in M.c.f. of such 
sweet gas and the royalty on the total volume of sour gas so produced and so 
sold or used shall never be less than three and one-half cents (3 1/2c) 
multiplied by one-eighth (1/8) of the total volume in M.c.f. of such sour gas. Whenever the weighted average price 
per M.c.f. received by Lessee from all sales of gas 
delivered within an area comprising Moore, Hartley, Sherman and Hansford 
Counties, Texas and Texas County, Oklahoma, during any calendar month, exceeds 
four cents (4c) per M.c.f., the royalty on the total 
volume of sweet gas so produced and so sold or used during the succeeding month 
shall be an amount equal to such weighted average price less one-half cent 
(1/2c) multiplied by one-eighth (1/8) of the total volume in M.c.f. of such sweet gas and the royalty on the total volume 
of sour gas so produced and so sold or used during such succeeding month shall 
be an amount equal to such weighted average price less one-half cent (1/2c) 
multiplied by one-eighth (1/8) of the total volume in M.c.f. of such sour gas.
 
* * * * *
 
The phrase ‘weighted average price per M.c.f. received by Lessee from all sales of gas’ shall mean 
the weighted average price, computed as hereinafter provided, received by Lessee 
and its subsidiaries from the sale to others than Lessee and its subsidiaries of 
natural gas and any components of natural gas, excluding sales of casinghead gas sold in its natural state, delivered by 
Lessee in the form of gas within the above designated area. In computing 
weighted average price, there shall not be deducted any cost of transportation 
or purification incurred by Lessee, and any amount per M.c.f. received by Lessee from the purchaser for 
transportation or purification prior to delivery shall be deemed to be a part of 
the price per M.c.f. received by Lessee.
 
* * * * * 
 
The term ‘weighted average price’ as used herein shall 
refer to weight with respect to volume and price only.
 
  
            
Subclass 2 includes approximately 
three to four thousand royalty owners in the Texas Panhandle with gas royalties 
governed by GRAs. Phillips produces natural gas from 
these leases, transports it miles away, and Phillips’ affiliate GPM Gas 
Corporation (GPM) processes liquid products at a processing plant from the 
natural gas produced from the wells. The liquid products are then sold 
separately from the dry residue gas. 
            
The general formula for paying royalties is the volume of gas production 
multiplied by price, adjusted for the interest owned. Specifically, the GRAs provide that the royalty due is the “weighted average 
price” multiplied by the total volume of natural gas production in M.c.f. times the one-eighth royalty interest, for gas 
delivered within the defined five-county area.[6] 
            
These royalty owners complain that Phillips calculates their royalties 
based only on the dry residue natural gas production and excludes the liquid 
components, which are separated from the gas by Phillips’ downstream processing. 
See Mapco Inc. v. Pioneer Corp., 615 F.2d 297, 298 (5th Cir. 1980) 
(discussing separation of natural gas liquids from “dry gas”). Liquid products 
of natural gas can include natural gas liquids or Liquid Natural Gas (LNG). 
Natural gas liquids are heavier hydrocarbons (such as ethane and propane) that 
are separated from the lighter natural gas (methane). 8 Howard R. Williams & Charles J. Meyers, 
Oil and Gas Law: Manual of Oil and Gas Terms, at 600, 634, 835 (2007). 
Natural gas liquids are extracted from natural gas at processing plants away 
from the wellhead. See ConocoPhillips Co. v. Incline Energy, Inc., 189
S.W.3d 377, 379 (Tex. App.—Eastland 2006, pet. denied). LNG, by contrast, is 
liquid methane processed by cooling natural gas to approximately -260 degrees 
Fahrenheit, at which point the gas condenses to a liquid state. Rachel Clingman & Audrey Cumming, The 2005 Energy Policy 
Act: Analysis of the Jurisdictional Basis for Federal Siting of LNG Facilities, 2-1 Tex. J. Oil, Gas, & Energy L. 57, 
60 (2007). This reduces the volume of the gas by a factor of 600 to 1, making it 
easier to transport and store. Id.
            
Phillips interprets the GRAs to require royalty 
payments without accounting for the prices received for natural gas liquids or 
LNG, which GPM processes miles away.[7] The royalty 
owners argue Phillips’ practice of using only dry residue gas prices to 
calculate weighted average price, rather than using the prices obtained from 
selling the gas before the liquid components are removed, constitutes a breach 
of the GRAs. If sales of natural gas liquids and LNG 
are included in the weighted average price, the price factor of the royalty 
formula will be higher as “wet” gas is more valuable than dry residue natural 
gas. If they are not, the price factor will be lower. The royalty owners contend 
that the phrase “weighted average price per M.c.f. 
received by Lessee from all sales of gas” includes the price Phillips receives 
for sales to third parties of natural gas liquids and LNG.
            
The royalty owners also complain that the royalty formula should account 
for the varying heat content of the components of gas produced. Natural gas is 
measured in one of two ways. One method, the volumetric method, measures the 
volume of space the gas occupies at a specified pressure and temperature. The 
industry measurement unit, abbreviated as “Mcf,” for 
this method equals one thousand cubic feet of gas, measured at a specified 
pressure and temperature.[8] Williams & 
Meyers, supra, at 596. In short, one Mcf is the amount of gas at a particular pressure and 
temperature needed to fill a cube ten feet wide by ten feet long by ten feet 
high. The other method for measuring natural gas values the heating content of 
the gas, including its components. The heating content of gas will vary from 
well to well, depending on the mixture of hydrocarbon and non-hydrocarbon 
molecules, and the mixture of simple versus complex hydrocarbons.[9] The industry 
measurement unit for this method is the British thermal unit, abbreviated “Btu.” 
Id. at 110.
            
While Phillips calculates royalty payments based on the number of Mcfs, the royalty owners argue the phrase “weighted average 
price per M.c.f.” should account for the varying Btu 
content of the gas streams. The royalty owners claim their natural gas contains 
higher Btu components and calculating royalties based on the heating content of 
gas produced would require Phillips to pay higher royalties. 
            
Of course, the method of measuring gas for the royalty formula is 
determined by the agreement. We first address the contention that the GRAs are ambiguous. The court of appeals held that Subclass 
2 failed to meet the predominance requirement because the trial court implicitly 
found the GRAs were ambiguous on the issue of valuing 
natural gas production. 108 S.W.3d at 397–98. Notwithstanding the GRA 
provisions, the trial court proposed to send the issue to the jury and “require 
the jury to state the formula that [Phillips] should have used to compute 
royalty payments under the [GRAs].” The trial court, 
in essence, instructed the jury to interpret the phrase “weighted average price 
per M.c.f.” in the GRA as either a volumetric 
measurement or a measure of both volume and heat content. The jury would have to 
hear evidence to decide the intentions of thousands of individual royalty owners 
who executed GRAs and determine whether the parties 
reached a “meeting of the minds” on the formula for calculating royalties. 
See Lenape Res. Corp., 925 S.W.2d 
at 574 (stating the intentions of the parties control a contract’s meaning). 

            
The court of appeals thus held that individual issues would predominate 
over common issues, making the claims inappropriate for class certification. 
See Schein, 102 S.W.3d at 693. We agree with the court of appeals that by 
sending the interpretation of the GRAs to the jury, 
the trial court implicitly held the GRAs were 
ambiguous. See Thomas v. Long, 207 S.W.3d 334, 339–40 (Tex. 2006) 
(holding that court of appeals was correct to consider appeal of trial court’s 
implicit ruling).
            
However, we disagree that the GRA provisions at issue are ambiguous. 
Whether a contract is ambiguous is a question of law, subject to de novo review. 
Heritage Res., Inc. v. Nationsbank, 939 S.W.2d
118, 121 (Tex. 1996); see Coker v. Coker, 650 S.W.2d 391, 393 (Tex. 
1983). The royalty sections of the GRAs state with 
specificity how the royalty should be determined and define various terms used 
in the calculation. The GRAs state that Phillips must 
pay a royalty “on all sweet gas and sour gas, including all the components 
thereof, produced from said land and sold or used off the premises.” 
(Emphasis added.) The GRAs then provide that this 
volume of gas will be multiplied by a price of no less than four cents or a 
“weighted average price” if it is more than four cents. The GRAs define the phrase “weighted average price per M.c.f. received by [Phillips] from all sales of gas” to mean 
“the weighted average price . . . received by [Phillips] and its subsidiaries 
from the sale to others than [Phillips] and its subsidiaries of natural gas 
and any components of natural gas, excluding sales of casinghead gas sold in its natural state, delivered by 
[Phillips] in the form of gas within the [listed counties].” (Emphasis added.) 
The GRAs require Phillips to pay a royalty on the 
natural gas produced “including all the components thereof” (or alternatively 
phrased as “any components of natural gas”). Liquid products are originally 
constituent parts of the natural gas produced by Phillips and delivered to GPM. 
This indicates that when determining the prices of natural gas to include in the 
weighted average price factor in the royalty formula, all the natural gas 
metered at the royalty owners’ wells should be included, before any later 
extraction of natural gas liquids or LNG. In sum, the royalty owners are 
entitled to a royalty based on the value of the natural gas, including all of 
its components.
            
Phillips argues that the phrase “delivered by [Phillips] in the form of 
gas” should limit the weighted average price to only the prices received for the 
sale of natural gas in the form of gas. Although sophisticated parties in 
today’s market might enter a contract that distinguishes the forms and 
components of natural gas, the GRAs in the present 
case were entered long before extraction and sale of natural gas liquids was 
commonplace. The GRAs evidence the parties’ intent to 
base a royalty on the value of the natural gas before separation of liquid 
components has occurred. 
            
On the other hand, the royalty owners are incorrect insofar as they 
suggest the royalty should be based on the average of prices Phillips receives 
for the separate sales of dry residue gas and liquid components. The GRAs specifically state that “amount[s] per M.c.f.” received for transportation and purification of the 
gas shall not be deducted from the sales prices when averaging prices for 
royalty purposes. The GRAs do not state that similar 
premiums received for any voluntary processing Phillips undertakes may also not 
be deducted from the sales price when averaging. In other words, just as the 
GRAs do not contemplate Phillips separating liquid 
components from dry residue gas before calculating a royalty, they do not 
evidence the intent to give the royalty owners the benefit of the value added by 
further processing. To read the GRAs otherwise would 
give the royalty owners the benefit of costs and risks Phillips voluntarily 
undertook.
            
This interpretation not only adheres to the terms of the agreement, it 
also comports with industry practice. Subject to their agreements, royalty 
owners generally are entitled to a royalty on the total amount of minerals they 
sell from their mineral estate, including all components of those minerals—no 
less and no more. Sowell, 789 F.2d at 1158. This principle is limited, 
however, by other considerations. Unless otherwise specified in the mineral 
lease, generally, the lessee or producer will bear both the cost and benefits 
from processing and treatment of those minerals after the initial production. We 
have explained that “[h]aving bought and paid for such 
gas [the lessee] owned the same, including all of its constituent elements, and 
therefore had the lawful right to make such use of it as it might deem 
proper.” Lone Star Gas Co. v. Stine, 41 S.W.2d 48, 49 (Tex. Comm’n App. 1931, judgm’t 
adopted); Lone Star Gas Co. v. Harris, 45 S.W.2d 664, 667 (Tex. Civ. 
App.—Eastland 1931, writ ref’d) (same); see 
also ConocoPhillips Co., 189 S.W.3d at 381 (holding royalty 
calculation not required to include natural gas liquids production when 
agreement calls for metering before liquids are removed); Carter v. Exxon 
Corp., 842 S.W.2d 393, 394, 397 (Tex. App.—Eastland 1992, writ denied) 
(holding production of natural gas liquids not included in royalty for “gas, 
including casinghead gas or other gaseous substance”). 
Nothing in the GRAs at issue indicate an intent to 
change these common principles.
            
The royalty owners’ second argument—that the royalty formula should 
account for the Btu content of the natural gas—finds no support in the language 
of the GRA provisions. To the contrary, the GRAs 
expressly state the “weighted average price” refers to “weight with respect to 
volume and price only” and make no mention of the heating content in 
determining the royalty. (Emphasis added.) Thus the GRAs do not provide for an adjustment for heating content or 
value or an incorporation of Btus as a measurement. 

            
We therefore conclude that the pricing provisions of the GRAs are unambiguous and may be construed classwide for royalty owners who executed substantially 
identical GRAs. The GRAs in 
Subclass 2 require royalties to be paid based on the volume of natural gas 
metered at the wells multiplied by a price averaged from sales to third parties, 
before liquid products are extracted or processed. The trial court erred in its 
trial plan by proposing to send the interpretation of the GRAs to the jury and, accordingly, the court of appeals 
erred in decertifying Subclass 2 on predominance grounds.
            
The court of appeals also decertified Subclass 2 on another ground, 
holding that representatives Royce Yarbrough and Ted Powell were not adequate 
representatives. 108 S.W.3d at 398–401. It is the trial court’s duty to ensure 
that “the class representative is adequately representing the rights of absent 
class members in all aspects of the class litigation.” Daccach, 217 S.W.3d at 447. The class representative 
has the burden of proving adequacy. See Compaq, 135 S.W.3d at 672. One 
component of adequacy is the absence of conflict between a class representative 
and the class members. See State Farm Mut. Auto. 
Ins. Co. v. Lopez, 156 S.W.3d 550, 556 (Tex. 2004) (“[A] class 
representative whose interests conflict with those of other class members may 
not adequately represent a class.”). In the case of Yarbrough, Phillips contends 
that a royalty calculation formula including adjustments for heat content would 
actually lower the royalties Yarbrough receives due to the poorer composition of 
gas from her well. As we have determined that the GRAs 
do not include any adjustments for heat content of various wells, Yarbrough’s 
interests do not conflict with the class. The court of appeals erred in finding 
her an inadequate class representative on this basis. 
            
The second class representative is Ted Powell. The court of appeals 
determined that there was no evidence before the trial court on which it could 
conclude that Powell was an adequate representative. 108 S.W.3d at 400–01. At 
the certification hearing in March 2002, Phillips challenged Yarbrough’s 
adequacy. The royalty owners then added Powell as a representative for Subclass 
2 and his deposition was taken in May 2002. In a letter dated June 14, 2002, 
which was hand-delivered to the trial court, the royalty owners stated that the 
transcript of Powell’s deposition was attached to the letter and provided 
evidence to support his adequacy as a class representative. Phillips does not 
contend that the evidence in the deposition is insufficient to support a finding 
of adequacy, and we do not reach that issue. Instead, Phillips asserts that 
there is no proof that Powell’s deposition was before the trial court when it 
signed the certification order on June 14, 2002. Although the June 14th letter 
is file-stamped June 14, 2002, the deposition is stamped “filed” on June 23, 
2002, one week after the certification order was signed. If the trial court did 
not have the deposition on June 14th when it signed its order, the trial court 
would have abused its discretion in certifying the class with Powell as a 
representative as there would be no evidence to establish his adequacy. The 
royalty owners have not established that the deposition was available to the 
trial court when it signed the order. See Compaq, 135 S.W.3d at 
672 (stating class representative has the burden at the trial court to establish 
the prerequisites for class certification). Accordingly, there is no evidence on 
which to base a determination that Powell carried his burden to establish his 
adequacy as a class representative.
            
For the foregoing reasons, we conclude that the court of appeals erred in 
finding that the GRAs were ambiguous. We agree that 
Powell has not shown that he is an adequate representative for Subclass 2, but 
hold that Yarbrough’s interests are not in conflict with the class. Therefore we 
reverse the court of appeals’ judgment decertifying Subclass 2.
C. Subclass 3
            
Subclass 3 is comprised of royalty owners in the Texas Panhandle whose 
leases provide for royalties, either under an amount-realized/proceeds basis or 
under a market-value basis, in which Phillips has sold gas under a “percentage 
of the proceeds” (POP) contract with its affiliate GPM. A POP contract is a gas 
purchase contract providing payment to the purchaser as a percentage of the 
proceeds realized by the purchaser upon the resale of the gas. Williams & Meyers, 
supra, at 751. The 
POP contracts here provide for Phillips to receive a price for the raw natural 
gas based on the volume of residue gas and natural gas liquids after GPM gathers 
and processes the gas. A typical POP contract includes an “80/20” split between 
the lessee and subsequent purchaser, similar to the percentages in the contracts 
at issue for Subclass 3. In such a contract, Phillips would receive a gas price 
calculated by adding eighty percent of the proceeds GPM receives for residue gas 
times the volume and eighty percent of the published prices for liquids times 
the volume. Thus, GPM would retain for itself twenty percent of the proceeds 
from the resale of the gas. 
            
The royalty owners argue the 80/20 split, or other similar percentages, 
constitutes an unreasonable and fraudulent post-production fee for GPM. They 
argue Phillips breached its covenant “to manage and administer the leases as a 
reasonably prudent operator” based on this “excessive” processing charge. 
Holding Subclass 3 failed to meet the predominance requirement, the court of 
appeals reversed certification based on the numerous individual factors the jury 
would need to consider to determine if Phillips breached its duty by paying 
unreasonable fees to GPM. The court of appeals did not address Phillips’ 
argument that there is no recognized implied covenant to manage and administer 
the lease properly. We address the royalty owners’ claim that Texas recognizes 
an implied duty to manage and administer gas leases, as well as the reasons 
expressed by the court of appeals for decertification.
            
In their brief, the royalty owners do not address the potential 
individual factors, but instead focus on the question common to the subclass: 
whether the fees under the POP contracts are unreasonable. The royalty owners 
emphasize the legal issue common to the subclass is Phillips’ duty to manage and 
administer the lease as a reasonably prudent operator, which they allege we 
recognized in Yzaguirre. This duty, they argue, 
applies to all members of the subclass, whether they have a proceeds-based or 
market-value based lease.
            
The royalty owners, however, provide no comprehensive explanation of a 
broad implied “duty to manage and administer the lease,” nor do they distinguish 
this duty from the recognized duty to market as a reasonably prudent operator. 
As we discussed in Amoco, the “duty to manage and administer” the lease 
is one of three broad categories of implied covenants recognized by law and gas 
treatises. Amoco Prod. Co., 622 S.W.2d at 567. In Yzaguirre, we recognized the implied duty to manage 
and administer the lease included the duty to market the oil and gas reasonably, 
citing our holding in Amoco. Yzaguirre, 
53 S.W.3d at 373 (citing Amoco Prod. Co., 622 S.W.3d at 567). Thus, the 
royalty owners misread our holding in Yzaguirre 
to suggest we have recognized a “duty to manage and administer the lease as a 
reasonably prudent operator” distinct from a duty to market as a reasonably 
prudent operator. In addition, the royalty owners have failed to provide support 
for the proposition that, at its core, Subclass 3 concerns anything more than 
Phillips’ alleged failure to diligently market the gas and obtain a higher 
price, subject to the same limitations we have already expressed for that 
implied duty.
            
Whether brought under the broad duty to manage and administer the lease 
or under the specific duty to market, Subclass 3 may not be certified because it 
expressly includes both proceeds/amount realized and market value leases. As we 
discussed in Hankins, a class such as Subclass 3 would fail the Rule 42 
commonality requirement by including both types of leases. 111 S.W.3d at 74–75. 
Like Hankins, the inquiry under a market value lease would be different 
than under a proceeds lease. Market value leases provide an objective basis for 
calculating royalties independent of the price the lessee actually obtains, and 
thus we do not recognize an implied covenant to obtain a better price for such 
oil and gas leases. Yzaguirre, 53 S.W.3d at 
374. Since market value leases do not have such an implied covenant, while 
proceeds leases do, Subclass 3 does not satisfy the commonality requirement of 
Rule 42. See Hankins, 111 S.W.3d at 74–75 (holding that even under the 
commonality requirement’s low threshold, a class with both proceeds leases and 
market value leases would fail). 
            
Finally, the royalty owners fail to explain how a reasonable processing 
fee can be proven classwide, even for proceeds leases 
only. Subclass 3 involves POP contracts for gas processed at three different GPM 
processing plants in the Panhandle. Many of the contracts have percentages 
different from the general 80/20 ratio. A factual analysis of the circumstances 
surrounding each POP contract would be necessary to ascertain if the production 
fee was reasonable or if Phillips breached any duties owed. Like Subclass 1, 
individual issues would predominate. Thus, the trial court abused its discretion 
by certifying Subclass 3.
V. CONCLUSION
            
For these reasons, we conclude the trial court abused its discretion in 
certifying Subclasses 1 and 3 of royalty owners. We affirm on different grounds 
the court of appeals’ judgment decertifying Subclasses 1 and 3, but reverse the 
judgment decertifying Subclass 2, and remand the case to the trial court for 
further proceedings consistent with this opinion.
 
 
________________________________________
                                                                        
J. Dale Wainwright
                                                                        
Justice
 
 
OPINION DELIVERED: February 15, 2008

[1] 
The language of the former Rule 42(b)(4), adopted from 
the revised Federal Rule of Civil Procedure 23(b)(3), is now codified as Rule 
42(b)(3), effective January 1, 2004. BMG Direct Mktg., Inc. v. Peake, 178 S.W.3d 763, 777 n.10 (Tex. 2005). For ease of 
reference, we will refer to (b)(3) as including the former (b)(4) paragraph. 

[2] 
The following is an example of such a clause:
 
As royalty, lessee covenants and agrees: . . . [t]o pay 
lessor on gas and casinghead 
gas produced from said land (1) when sold by lessee, one-eighth of the amount 
realized by lessee, computed at the mouth of the well, or (2) when used by said 
lessee off said land or in the manufacture of gasoline or other products, the 
market value, at the mouth of the well, of one-eighth of such gas and casinghead gas.

[3] 
An example of such an express clause, found in the Bowden family leases, 
provides:
 
Lessee covenants and agrees to use reasonable diligence 
to produce, utilize, or market the minerals capable of being produced from said 
wells, but in the exercise of such diligence, lessee shall not be obligated to 
install or furnish facilities other than well facilities and ordinary lease 
facilities of flow lines, separator, and lease tank, and shall not be required 
to settle labor trouble or to market gas upon terms unacceptable to 
lessee.

[4] 
The reasonably prudent operator concept is infused into every implied covenant 
in the oilfield. “Every claim of improper operation by a lessor against a lessee should be tested against the general 
duty of the lessee to conduct operations as a reasonably prudent operator in 
order to carry out the purposes of the oil and gas lease.” Amoco Prod. Co. v. 
Alexander, 622 S.W.2d 563, 568 (Tex. 1981). Specifically, “the standard of 
care in testing the performance of implied covenants by lessees is that of a 
reasonably prudent operator under the same or similar facts and circumstances.” 
Id. at 567–68; Shell Oil Co. v. Stansbury, 410 S.W.2d 187, 188 
(Tex. 1966).

[5] 
For example, if a class produced evidence that wells substantially identical to 
the class wells were being marketed at the wellhead to third parties for a 
greater price than Phillips was receiving, such 
evidence might satisfy the predominance requirement. Or if a class offered 
evidence that Phillips was artificially lowering the prices it charged PGM for 
gas sales across the board or that Phillips was systematically miscalculating 
the royalty payments, such claims might be more susceptible to certification. 
See, e.g., Duhe v. Texaco, Inc., 
99-2002 (La. App. 3 Cir. 02/07/01); 779 So. 2d 1070, 1082 (holding there was a 
common class question on whether the lessor’s royalty 
formula correctly reflected market value).

[6] 
There are different minimum weighted average prices, not relevant here, for the 
production of sweet gas compared to sour gas. Sweet gas generally is natural gas 
not contaminated with impurities, such as sulfur compounds. As opposed to sour 
gas, it is ready for commercial and domestic use once liquid constituents have 
been removed. Gas is considered sour when it is “contaminated with chemical 
impurities, notably hydrogen sulphide or other sulfur 
compounds, which impart to the gas a foul odor. Such compounds must be removed 
before the gas can be used for commercial and domestic purposes.” 8 Howard R. Williams & Charles J. Meyers, 
Oil and Gas Law: Manual of Oil and Gas Terms, 986 (2007). 
                
    

[7] 
We note that the royalty owners do not complain about a third type of liquid 
product found in natural gas production called condensate. Condensate is 
hydrocarbons that exist in the form of gas when contained in the natural gas 
reservoir underground, which condense into a liquid form when released from the 
reservoir’s higher pressure and temperature. Williams & Meyers, 
supra, at 186.1. 
Condensate is typically collected prior to metering at the wellhead and is 
therefore considered separately from liquids processed after metering. See 
Sowell v. Nat. Gas Pipeline Co. of Am., 789 F.2d 1151, 1153, 1158 (5th Cir. 
1986) (holding plaintiffs were not entitled to royalties for liquids that 
condense after metering). The royalty owners in the present case complain only 
of Phillips’ removal of liquid products at processing plants after metering has 
occurred. Accordingly, this opinion considers only natural gas liquids and LNG 
production, rather than condensate production.

[8] 
The GRAs provide that the term “‘M.c.f.’ shall mean one thousand (1,000) cubic feet of gas 
computed to a base pressure of sixteen and four-tenths (16.4) pounds per square 
inch absolute and a base temperature of sixty (60) degrees 
Fahrenheit.”

[9] 
Natural gas from a well can be composed of both hydrocarbons, which are 
combustible, and non-hydrocarbons, which are inert. Williams & Meyers, 
supra, at 633. Hydrocarbons can vary in chemical 
makeup, from simple methane to the very complex octane, and in form, from a pure 
gaseous state to condensate. Id. at 480. The non-hydrocarbon makeup of 
natural gas can include gases such as helium, sulfur, and nitrogen. Id. 
at 633.