HighMount Exploration & Production LLC, and Dominion Oklahoma Texas Exploration & Production, Inc. v. Harrison Interests, LTD., Dan J. Harrison III, and BFH Mining LTD.

05/13/2015

Cause No. 14-15-00058-CV

IN THE FOURTEENTH COURT OF APPEALS
HOUSTON, TEXAS
________________________________________________________

HIGHMOUNT EXPLORATION & PRODUCTION, INC.,
AND DOMINION OKLAHOMA TEXAS EXPLORATION
& PRODUCTION, INC.
Appellants,
v.

HARRISON INTERESTS, LTD., DAN J. HARRISON, III,
AND BFH MINING, LTD.,
Appellee.
_________________________________________________________
On Appeal from Cause No. 2009-06060
In the 190th Judicial District Court of Harris County, Texas
The Honorable Patricia J. Kerrigan Presiding

APPELLANTS’ BRIEF

FARNSWORTH & vonBERG, LLP
T Brooke Farnsworth
brooke@fvllp.com
ORAL ARGUMENT State Bar No. 06828000
REQUESTED Bennett S. Bartlett
bennett@fvllp.com
State Bar No. 01842440
333 North Sam Houston Parkway, Suite 300
Houston, Texas 77060
(281) 931-8902 – telephone
(281) 931-6032 – facsimile
ATTORNEYS FOR APPELLANTS
 IDENTITY OF PARTIES AND THEIR COUNSEL

The following is a complete list of the names and addresses of all parties to the
trial court's final judgment, or their successors in interest, and the names and
addresses of all trial and appellate counsel:

APPELLANTS: APPELLEES:

EnerVest Operating, LLC, Harrison Interests, Ltd.,
(successor in interest to HighMount Dan J. Harrison, III, and
Exploration & Production LLC), and BFH Mining, Ltd.
EnerVest Energy Institutional
Fund XIII-A, L.P., EnerVest Energy
Institutional Fund XIII-WIB, L.P., and
EnerVest Energy Institutional
Fund XIII-WIC, L.P. (successors to
HighMount Exploration & Production
Texas LLC).

COUNSEL: COUNSEL:

T Brooke Farnsworth Charles S. Kelley
State Bar No. 06828000 State Bar No. 11199580
Bennett S. Bartlett Quinncy N. McNeal
State Bar No. 01842440 State Bar No. 24074690
Farnsworth & vonBerg, LLP Mayer Brown LLP
333 North Sam Houston Parkway 700 Louisiana Street
Suite 300 Suite 3400
Houston, Texas 77060 Houston, Texas 77002
telephone: 281-931-8902 telephone: 713-238-3000
facsimile: 281-931-6032 facsimile: 713-238-4703
www.farnsworthvonberg.com www.mayerbrown.com

TRIAL JUDGE:
Patricia J. Kerrigan
190th Judicial District Court

i
 TABLE OF CONTENTS

IDENTITY OF PARTIES AND THEIR COUNSEL. . . . . . . . . . . . . . . . . . . . . . . . i

TABLE OF CONTENTS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

INDEX OF AUTHORITIES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv

STATEMENT OF THE CASE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi

STATEMENT ON ORAL ARGUMENT. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi

ISSUES PRESENTED FOR REVIEW. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii

STATEMENT OF FACTS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

ARGUMENT SUMMARY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

ARGUMENT.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

I. STANDARD OF REVIEW.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

II. KEY PROVISIONS OF THE ROYALTY AGREEMENT.. . . . . . . . . . . . . . . . . . . . . 7

A. The royalty calculation methodology in the agreement. . . . . . . . . . . . 7

B. The post-production cost-sharing methodology in the
agreement.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

III. THE TWO ISSUES CHALLENGED IN THIS APPEAL. . . . . . . . . . . . . . . . . . . . . . 13

A. Harrison's simplistic reading of the fuel gas provision is
contradicted by other specific provisions of the agreement, and by
an integrated reading of the agreement as a whole. . . . . . . . . . . . . . 13

ii
 B. Because the majority of the natural gas from the Subject Interests
is compressed "downstream" from components of a "central
facility," HighMount's compression charges are permissible
"Marketing Costs" under the royalty agreement. . . . . . . . . . . . . . . . 20

CONCLUSION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

PRAYER. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

CERTIFICATE OF COMPLIANCE.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

CERTIFICATE OF SERVICE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

iii
 INDEX OF AUTHORITIES

Cases:

Alamo Nat'l Bank v. Hurd, 485 S.W.2d 335
(Tex. Civ. App.— San Antonio 1972, writ ref'd n.r.e.). . . . . . . . . . . . . . . . . 1

Atlantic Richfield Co. v. Holbein,
672 S.W.2d 507 (Tex. App.—Dallas 1984, writ ref'd n.r.e.) .. . . . . . . . . . . 13

Bendigo v. City of Houston, 178 S.W.3d 112
(Tex. App.— Houston [1st Dist.] 2005, no pet.). . . . . . . . . . . . . . . . . . . . . . 6

Birnbaum v. SWEPI, LP,
48 S.W.3d 254 (Tex. App.—San Antonio 2001, pet. denied). . . . . . . . . . . 13

Cigna Ins. Co. v. Rubalcada, 960 S.W.2d 408
(Tex. App.— Houston [1st Dist.] 1998, no pet.). . . . . . . . . . . . . . . . . . . . . . 6

Comm'rs Ct. v. Agan, 940 S.W.2d 77 (Tex. 1997). . . . . . . . . . . . . . . . . . . . . . . . . . 6

Forbau v. Aetna Life Ins. Co., 876 S.W.2d 132 (Tex. 1994). . . . . . . . . . . . . . . . . 19

Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996). . . . . . 9, 10

MMP, Ltd. v. Jones, 710 S.W.2d 59 (Tex. 1986). . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Read v. Britain, 414 S.W.2d 483(Tex. Civ. App.— Amarillo),
aff'd, 422 S.W.2d 902 (Tex. 1967). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Royal Indem. Co. v. Marshall, 388 S.W.2d 176 (Tex. 1965). . . . . . . . . . . . . . . . . 19

Santanna Natural Gas Corp. v. Hamon Operating Co.,
954 S.W.2d 885 (Tex. App.— Austin 1997, pet. denied). . . . . . . . . . . . . . 18

iv
Other Authorities:

Edward B. Poitevent, II, Post-Production Deductions from Royalty,
44 S. Tex. L. Rev. 709 (Summer 2004). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Ernest E. Smith and Jacqueline Lang Weaver,
Texas Law of Oil and Gas (2nd ed. 2014 LexisNexis). . . . . . . . . . . . . . . . . . 9

Patrick H. Martin and Bruce M. Kramer,
Williams & Meyers, Oil and Gas Law (LexisNexis 2014).. . . . . . . . . . . . . 10

Williams & Meyers, Manual of Oil & Gas Terms (14th ed. 2009). . . . . . . . . . . . 17

v
 STATEMENT OF THE CASE

Nature of the Case: Appellee royalty interest owners brought suit alleging that
the appellants breached an oil and gas royalty agreement by
improperly deducting post-production costs from appellees'
royalty payments.

Trial Court: The 190th Judicial District Court of Harris County, Texas
The Honorable Patricia J. Kerrigan presiding.

Trial Disposition: Trial court granted summary judgment finding that
appellants (1) improperly deducted marketing charges from
appellees' royalty payments, and (2) failed to pay royalties
to appellees on natural gas used as fuel in compressors
necessary to transport natural gas to third party lines. The
final judgment awards specific damages.

STATEMENT ON ORAL ARGUMENT

How the parallel natural gas streams at issue in this appeal are gathered,

transported, treated, and processed, particularly in light of industry custom and

practice, bears heavily on the legal questions in this appeal. HighMount believes oral

argument will assist the court in understanding the facts underpinning the parties’

legal arguments.

vi
 ISSUES PRESENTED FOR REVIEW

Issue No. 1: Payment of royalty on gas consumed as fuel.

The royalty agreement between HighMount as producer and Harrison as

royalty owner requires HighMount to pay royalties on the "gross proceeds" received

for gas remaining after processing. Did the trial court err in ordering HighMount to

pay royalty on gas used as fuel prior to processing when HighMount receives no

payment for natural gas used as fuel prior to processing?

Issue No. 2: Deduction of marketing costs.

The same agreement allows HighMount to charge Harrison 10 cents per MCF

of gas to recoup capital costs for equipment installed "downstream" from a defined

type of gas production facility. Did the trial court err in disallowing all of

HighMount's charges when only a small portion of the gas does not pass through

equipment installed downstream from such a facility?

vii
 STATEMENT OF FACTS

Introduction

This appeal asks the court to construe an oil and gas royalty agreement.1 The

agreement was written in 1990 in conjunction with Harrison Interests' sale of mineral

interests to Meridian Oil Production Inc. R 9. As part of the consideration for the sale,

the appellees (collectively, "Harrison") reserved a 5% non-participating royalty

interest in conveyed properties and a 5% overriding royalty interest in conveyed

leases.2 R 9. The agreement defines the conveyed properties and leases together as

the "Subject Interests." R 19.

HighMount acquired Meridian's interest in 2007 from Dominion, also an

appellant. R 499. Based upon a review of audited royalty payment records, it appears

that HighMount was using the same accounting practices (at least up to the time

Harrison brought this suit) for royalty payments under the parties' agreement that both

Dominion and the earlier royalty payors had been using. R 324, 499-500.

1
A copy of the agreement is included as appendix B. Because the only copies of the
agreement in the record are degraded photocopies, we have retyped the relevant provisions of the
agreement and have included them in appendix B
2
While there are distinctions between nonparticipating royalties and overriding royalties,
those distinctions have no bearing on this dispute. See generally Alamo Nat'l Bank v. Hurd, 485
S.W.2d 335, 339 (Tex. Civ. App.— San Antonio 1972, writ ref'd n.r.e.) (discussing several Texas
Supreme Court decisions holding that an overriding royalty is royalty).

1
 Shortly after HighMount's acquisition of the Subject Interests in 2007, Harrison

hired a valuation analyst named Alton R. Davis to audit HighMount's royalty

payments. R 320. The audit process continued over the next two and a half years (that

period included a litigation tolling agreement between the parties), and culminated

in an audit report in the summer of 2010. Id. This appeal arises from a summary

judgment against HighMount over two issues from the audit report that the parties

could not resolve. Appx A.

Gas Production from the Subject Interests

The issues in dispute concern, first, HighMount's use of gas produced from the

Subject Interests to power gas compressors and gathering equipment on the Subject

Interests before the gas is sold to a third party, and second, a marketing charge of 10¢

per thousand cubic feet ("MCF") of gas that HighMount charges Harrison for

preparing gas from the Subject Interests for market. A review of HighMount's

post-production activities will help put these two issues in context.

HighMount or its affiliate gathers gas from numerous wells on the Subject

Interests and then transports the gas through a field separator where liquids (oil and

water) are removed from the gas and sent to tanks. R 502-03. Approximately 95% of

the gas produced from the Subject Interests is then sent to a central facility referred

to as the Canyon Ranch DP-6 Station ("DP6"). Id. A diagram of wells and gathering

2
lines on the Subject Interests is attached as appendix C. See R 583. DP6 has been

highlighted for the court's convenience.

Two separate gas streams enter DP6, a "lean" gas stream and a "rich" gas

stream. R 503. A diagram of the equipment and transmission lines at DP6 is included

as appendix D. See R 584. The two separate intake lines have been highlighted in

different colors, and the both lines begin at the top of the page.

The lean gas comes into DP6 in an 8-inch pipeline and immediately goes

through two compressors. R 503. After compression it goes through separators, an

amine unit,3 and a heater, and is then delivered to a third party for transportation to

market. Id.

The rich gas comes into DP6 through a 20-inch pipeline, immediately goes

through a separator and meter, and then flows through two compressors prior to

delivery to a third party, DCP Midstream, LLP, for transportation to DCP's Sonora

Plant. R 503. At the Sonora Plant, it is further compressed and processed to extract

natural gas liquids such as ethane, propane, butane, and natural gasoline. Id. The

remaining gas that then emerges from the plant outlet or "tailgate" of the Sonora

plant, primarily methane, is referred to as "residue gas." The residue gas is delivered

3
Amine units are used to remove contaminants from a gas stream, most commonly hydrogen
sulfide (H2S) and carbon dioxide (CO2).

3
at the tailgate to DCP Midstream for transportation to Katy, Texas where it is sold.

Id.4 Thus, the rich gas—unlike the lean gas—is compressed by HighMount after it

undergoes other processing steps rather than before.

The crux of this appeal is whether or not HighMount is correctly paying

royalties under the various inter-related terms of the royalty agreement. To answer

that question, the Court will have to apply provisions of the royalty agreement to the

processing steps just discussed. We will quote sections of the agreement below as

they become relevant.

ARGUMENT SUMMARY

The first issue in this appeal invokes the well-established rule that courts must

read a contract as a whole to ascertain the drafters' intent. Based on a single sentence

in the royalty agreement, Harrison argues that HighMount must find some way to pay

royalties on the small portion of gas from the gas stream that is consumed as fuel in

gathering and compressing the rest of the gas stream for market. The trouble with that

claim is that it runs counter to everything else in the agreement. It contradicts the

instruction that the royalty obligation will only reach fuel gas for which HighMount

alone receives "proceeds." It is incongruent with the fact that both parties share the

4
The remaining 5% of the gas goes through a facility named “DP2,” but Harrison has never
complained about or taken issue with paying any charges associated with DP2.

4
burden of the compression and gathering costs if a third party compresses and gathers

the gas. And it ignores the fact that royalties are paid on residue gas, which is the

gas remaining after processing, meaning that the gas used as fuel for processing is

excluded from the royalty calculation. Accordingly, this Court must reverse the

summary judgment in Harrison's favor and render a decision holding that the royalty

agreement does not require HighMount's successor in interest to pay royalties on gas

used as fuel before the gas stream is processed downstream.

The second issue, unlike the first, requires a remand because there is an open

fact question. While it is unquestioned that gas enters DP6 in two streams, Harrison's

expert witness discussed only the path taken through DP6 by the lean gas—the much

smaller gas stream. He concluded that because the lean gas stream was compressed

before undergoing the processes associated with a "central facility" (heating,

separating, and metering), the compression did not occur "downstream" from a central

facility and was therefore not eligible for the marketing deduction in the royalty

agreement.

In contrast, the larger rich gas stream, which Harrison's expert did not discuss,

is compressed after it undergoes the processes associated with a "central facility."

Consequently, that stream does qualify for the 10¢ per MCF marketing fee charged

by HighMount. Determining the correct charges cannot be accomplished by this

5
Court, however, because the parties never undertook the necessary discovery to

delineate the damages for rich gas from those for lean gas. Therefore, the trial court's

damage calculation must be reversed and remanded for further findings.

ARGUMENT

I. STANDARD OF REVIEW.

Because the trial court disposed of this case on summary judgment, its decision

is to be reviewed de novo. Bendigo v. City of Houston, 178 S.W.3d 112, 113 (Tex.

App.— Houston [1st Dist.] 2005, no pet.). When, as here, the parties filed competing

summary judgment motions on the same issues, and the trial court granted one and

denied the other, the court is to review the summary judgment evidence presented by

both sides and if possible determine all questions presented. Comm'rs Ct. v. Agan,

940 S.W.2d 77, 81 (Tex. 1997); Cigna Ins. Co. v. Rubalcada, 960 S.W.2d 408,

411-12 (Tex. App.— Houston [1st Dist.] 1998, no pet.). At the same time, because

HighMount was the losing party, this court must take all evidence favorable to

HighMount as true, indulge every reasonable inference in its favor, and resolve any

reasonable doubt in its favor as well. MMP, Ltd. v. Jones, 710 S.W.2d 59, 60 (Tex.

1986).

6
II. KEY PROVISIONS OF THE ROYALTY AGREEMENT.

A. The royalty calculation methodology in the agreement.

This appeal challenges two trial court rulings on the proper calculation of

Harrison's royalties. Understanding the royalty payment method established by the

royalty agreement is critical to understanding how the court erred in its rulings.

Paragraph 4 of the agreement contains the royalty payment provisions and is

divided into five subparagraphs. Subparagraph (a) provides that royalty payments are

to be measured not by the volume of gas produced but on the gross proceeds from gas

sold:

(a) As to gas produced or to be produced from the Subject
Interests under a Short Term Sale, the royalties shall be Owners' royalty
share of the gross proceeds for the first sale or disposition of the gas
from the Subject Interests, . . . . [Appx B ¶ 4 (emphasis supplied)].5

Subparagraph (c) provides that when produced gas contains liquid

hydrocarbons that can be separated from the gas stream and sold profitably, royalties

are owed on both the separated liquids and the residue gas, again, based upon on

gross proceeds:

(c) If the gas produced from any well situated on the Subject
Interests shall contain in suspension condensate, gasoline or other
natural gas liquid hydrocarbons that economically can be separated from

5
Subparagraph (b) is not relevant to this appeal because it only applies to long term sales
arrangements and there are no such arrangements.

7
 the gas by the installation by Producer of traps, separators or other
mechanical devices, then Producer shall install such devices on the
surface of the Property, and Owners shall receive royalty on the
condensate, gasoline or other natural gas liquids so recovered in
accordance with the terms of paragraph 3 [regarding royalties on oil],
together with royalty on the residue gas in accordance with the terms of
paragraphs 4(a) and 4(b) of this Royalty Agreement. [Appx B ¶ 4
(emphasis supplied)].

When produced gas, including previously separated gas, is processed6 for the

purpose of removing not only liquid hydrocarbons but other elements of value such

as sulfur, helium, and carbon dioxide, subparagraph 4(d) allows HighMount to

deduct processing costs from the royalty on the separated elements, while royalty on

residue gas is again measured on gross proceeds:

(d) If gas or casinghead gas or separated gas resulting from
field separation produced from the Subject Interests is processed at any
location by or for the account of Producer, or by or for the account of
any affiliate of Producer, for the recovery and sale or other disposition
for value of liquid hydrocarbons, helium, carbon dioxide, sulfur, or any
other elements of the gas steam, then in lieu of royalties on gas provided
in paragraphs 4(a) and 4(b), the royalties shall be Owners' royalty share
of the gross proceeds less Owners' royalty share allocable portion of the
reasonable, direct costs . . . of processing such gas in the plant for the
recovery of such liquid hydrocarbons, helium, carbon dioxide, sulfur
and other elements, and the royalties on the residue gas resulting from
such processing operation attributable to gas produced from the Subject

6
The royalty agreement defines "treating" to refer to the removal of contaminants from the
gas stream, explicitly stating that the term shall not refer to "processing" gas to remove valuable
liquid hydrocarbons for later sale. See Appx B ¶ 2 ("treating").

8
 Interests shall be in an amount and determined as provided in paragraphs
4(a) and 4(b) above;7 . . . . [Appx B ¶ 4 (emphasis supplied)].

Because all of the gas that enters DP6 is separated to remove valuable liquids,

and the rich gas is also later processed at the Sonora plant (R 500), subparagraphs

4(c) and 4(d) are the provisions applicable to this case. And both calculate royalty

as a proportion of the "gross proceeds" received for "residue gas."

B. The post-production cost-sharing methodology in the
agreement.

Royalty calculation disputes like the one presented here are common in Texas

jurisprudence.8 In the case of natural gas royalties in particular, disputes arise

because gas producers and royalty owners share rights to the same undivided gas

stream, yet only the producer controls how the gas is marketed and sold. And while

the established rule burdens the producer alone with the cost of bringing the gas to

the surface, royalty owners bear their proportionate share of the post-production costs

7
Notably, the final sentence of paragraph 4(d) protects the owner by insisting that its
combined royalties for the residue gas plus the separated and sold liquid hydrocarbons shall never
be less than the royalty that would have been paid if the liquids stayed in the gas stream and royalty
was paid on the unprocessed gas. Thus, Harrison suffers no loss if HighMount’s use of fuel to
process the gas does not result in an increased royalty. Appx B ¶ 4.
8
See generally Edward B. Poitevent, II, Post-Production Deductions from Royalty, 44 S.
Tex. L. Rev. 709, 713 (Summer 2004).

9
incurred between the mouth of the well and the eventual point of sale absent an

agreement to the contrary.9

Post-production costs are incurred because natural gas is almost never ready

for sale as it leaves the wellhead. By the time natural gas is sold, it has been treated

to remove constituent elements, compressed, and transported to the point of sale.

Each of these procedures has an associated cost. While parties are free to divide the

cost of those operations as they wish, the traditional approach divides the cost

proportionally between the parties based upon the parties' ownership percentages.10

The disputes in this appeal arise from a detailed agreement which bears all the

earmarks of sophisticated industry players who recognized that their gas would need

to undergo various post-production procedures before being transported to a

downstream point of sale. Before we turn to the two specific issues in this appeal, it

is important to look at the agreement as a whole to understand the overall cost-sharing

scheme that they applied to post-production costs.

9
See Ernest E. Smith and Jacqueline Lang Weaver, Texas Law of Oil and Gas, §4.6[C] (2nd
ed. 2014 LexisNexis) (The royalty “must bear its proportionate share of costs incurred subsequent
to production.”) citing Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996).
10
See generally Patrick H. Martin and Bruce M. Kramer, Williams & Meyers, Oil and Gas
Law, § 645 (LexisNexis 2014) (costs incurred subsequent to production are to be borne on a pro rata
basis between operating and nonoperating interests). Royalty is usually subject to post-production
costs, including taxes, treatment costs to render it marketable, and transportation costs. See also
Heritage Resources v. Nationsbank, 939 S.W.2d at 122.

10
 Following customary practice, the parties decided that the royalty owner would

bear its fair share of those costs. The agreement's "General Terms" allow the producer

to deduct marketing costs from the owner's royalty up to a maximum of 10¢ per MCF:

(b) All royalties shall be determined and delivered or paid to
Owners after deducting therefrom the following costs:

(i) as to gas produced from the Subject Interests,
Owners' royalty share of Producer's monthly Marketing Costs for
such gas; however, for purposes of this paragraph 7(b), Producer's
monthly Marketing Costs (whether actually incurred by Producer
or an affiliate of Producer or charged to the Producer by a third
party) shall not exceed ten (10) cents per MCF . . . [Appx B ¶
7.(b)(i)].

"Marketing Costs" includes post-production processes necessary to make the gas

marketable, and the parties burdened the royalty owner with its proportional share of

those costs up to a 10¢ per MCF maximum.

The agreement also allows the producer to deduct post-production costs

associated with extracting liquid hydrocarbons from the owner's royalty. Paragraph

4(d) of the agreement, which we quoted above, addresses the royalty to be paid on

both the extracted elements of the gas stream and the residue gas. The royalty on the

extracted elements is subject to a deduction for "[o]wners' royalty share allocable

portion of the reasonable, direct costs . . . of processing such gas in the plant for the

11
recovery of such liquid hydrocarbons, helium, carbon dioxide, sulfur and other

elements, . . . ." [Appx B ¶ 4(d)]. Again, the parties proportionately share those costs.

Transportation costs are yet another expense that may be deducted from the

royalty payments under the agreement. As we discuss in more detail in section III of

this brief, the parties chose to measure the owner's royalty percentage not by the

market value of the gas sold, but by the "gross proceeds" received for the gas. The

definition of "gross proceeds" instructs that third-party transmission fees are

deductible from royalty payments:

In the event Producer transports, or causes to be transported, gas
production from the Subject Interests on a gas transmission line to a
market or sale "gross proceeds" for such gas shall be determined after
deducting any fees or charges incurred by Producer from the owner of
the gas transmission line for such delivery or transportation to such
market or sale; [Id. ¶ 2 ("gross proceeds")].

Thus the agreement allows deduction of Marketing Costs, certain processing

costs, and transportation costs from the owner's royalty payments. These

post-production deductions share a common feature: they each benefit the parties

jointly. Compression makes gas marketable for both parties' benefit. Extracted liquid

hydrocarbons are sold for both parties' credit. Transportation takes gas in which both

parties have an interest to a location for sale. The agreement, in other words, has a

12
basic approach to post-production procedures: where the benefits are shared, the costs

are shared.

This cost-sharing arrangement can also be seen in the alternative marketing

arrangement the agreement permits (but that Harrison never opted to take advantage

of). The agreement allows the owner to take its gas in kind for short-term sales.11 If

Harrison did so, it would bear the costs of compressing and treating its own gas and

transporting that gas to market. Thus when, as here, the producer takes those steps for

the owner, it does so for both parties' benefit, and the parties share the agreed-upon

post-production costs proportionately.

III. THE TWO ISSUES CHALLENGED IN THIS APPEAL.

A. Harrison's simplistic reading of the fuel gas provision is
contradicted by other specific provisions of the agreement,
and by an integrated reading of the agreement as a whole.

The first issue in this appeal is whether or not Harrison should be paid royalties

on gas used as fuel to operate HighMount's compressors and gathering equipment in

the field. Compression and gathering are necessary steps in preparing the gas for

market, and HighMount's compressors and gathering equipment obviously require an

11
The relevant language in paragraph 7(g) of the agreement begins:

In the event that Owners' royalty share of gas is not committed to a Long Term Sale in accordance
with the provisions of this Agreement, then at any time and from time-to-time Owners make elect
to take Owners' royalty share of gas production in kind and use or market same for their own account
. . ..

13
energy source. Following industry custom, HighMount uses gas from the wells it

operates to run its compressors and gathering equipment.12

There is no question that the gas consumed as fuel improves the value of the

remaining gas by making it available for subsequent sale. And because the parties

have proportionate interests, the reduction in the gas quantity reduces the parties'

interests proportionately. Therefore, given the royalty agreement's cost-sharing

approach to post-production procedures, it follows that the parties would jointly

shoulder the loss of gas consumed for their mutual benefit.

Harrison nevertheless complains that it should be paid royalty on the gas used

as fuel. Its argument rests upon a selective reading of the single sentence that

constitutes paragraph 4(e) of the agreement:

(e) Owners shall receive their royalty share of the gross proceeds
for gas used or utilized on or off the Subject interests, such as gas used
for fuel.

Harrison's deceptively simple conclusion from this sentence is that HighMount must

find some way to pay Harrison for gas consumed in compression and gathering.

12
It is common industry practice to use gas as fuel to run treatment equipment on the lease
premises. See, e.g., Atlantic Richfield Co. v. Holbein, 672 S.W.2d 507, 516 (Tex. App.—Dallas
1984, writ ref'd n.r.e.) (“uncontroverted testimony was that it is an industry-wide practice to deduct
the allocated volume for fuel gas before computing the settlement owed to royalty owners);
Birnbaum v. SWEPI, LP, 48 S.W.3d 254, 255 (Tex. App.—San Antonio 2001, pet. denied) (trial
court's summary judgment finding that no royalties were due on gas used as plant fuel and
compressor fuel affirmed).

14
When this sentence is put in the context of the rest of the agreement, however, it

becomes clear that the drafters of the royalty agreement never intended for royalties

to be paid on fuel gas used in compression and gathering and there are several reasons

for this conclusion.

To begin with the most obvious, HighMount did not receive any "proceeds"

from the gas used to run the compressor or the gathering lines. We acknowledge that

the agreement defines the term "gross proceeds" quite broadly in an effort to reach

the different kinds of commercial arrangements a producer might make to sell the

produced gas:

"gross proceeds" shall mean the entire economic benefit and all
consideration in whatever form received by or accruing to Producer or
an affiliate of Producer, including but not limited to sales proceeds or
proceeds or benefits of an exchange, prepayments for future production,
reimbursements for severance taxes or for other taxes or costs,
settlements or payments for the release or amendment of a sales contract
or arrangement, and take-or-pay payments or settlements and the like,
and any insurance proceeds from lost or destroyed oil and gas, . . . .
[Appx B ¶ 2].

But even under that broad definition, HighMount's use of gas in compressing and

gathering does not qualify as the sort of "proceeds" that the parties intended to reach.

The sort of consideration that they did intend to reach can be discerned from

the subsequent sentences of the definition. Each example of the type of economic

benefit that the parties envisioned as "gross proceeds" is one in which the

15
producer—and the producer alone—would receive an economic benefit in a quid pro

quo exchange with another party other than the royalty owner: transactions such as

a prepayment for future production, a recovery under a take-or-pay arrangement, a

payment for the release of a contract, a payment of insurance proceeds for lost or

damaged gas, or the benefit of an exchange of some sort.

Unlike all of those examples, HighMount's use of gas for fuel does not arise

from any sort of exchange, sale, or other payment. HighMount receives nothing in the

way of proceeds or other direct consideration from any other party when it uses gas

for fuel. Instead, the gas consumed as fuel to compress and gather the rest of the gas

stream is a post-production "cost" to HighMount and Harrison alike rather than a

"proceed" of any sale or exchange.

Furthermore, the economic benefit that does flow from the use of gas as fuel

does not accrue exclusively "to Producer" as required by the definition of gross

proceeds. Appx B ¶ 2. Both parties obtain the benefit of the gas reaching a market as

a result of compression and gathering. If HighMount paid royalty on that gas,

Harrison would get a windfall, a double dip of sorts, because both parties would be

paid for gas sold at market, but only Harrison would also be paid for the gas

consumed in making the remaining gas marketable. This uneven treatment is at odds

with both the specific language of the agreement and the drafters' well-expressed

16
intent that the jointly-benefitting parties share in the post-production costs required

to obtain those benefits.

A further problem with Harrison's reading becomes apparent when one is

confronted with the difficulty of putting a value on gas used as fuel. There are no

proceeds received for the gas from which one could calculate Harrison's royalty. Nor

is there any sort of exchange or trade that one could look to as a relative value. The

sale price many miles downstream is not directly helpful because the gas has a very

different value at that location, having been augmented by compression, processing,

and transportation.

Royalty could be calculated based on the downstream value by "backing out"

the specific charges for treatment and transportation (as is typically done for so-called

"market value" leases). But under the parties’ agreement here there are no such

charges to back out. Even Harrison's own expert never identified a value for the gas

used to fuel the compressors, simply using the sales price at Katy, Texas. R 440,

757. That price is not comparable, however, because the gas that is sold in Katy has

traveled several hundred miles and has been compressed more than once along the

route. In short, there is simply no metric for measuring the "proceeds" value of gas

burned up in the process of compressing, treating, and thereby enhancing the value

of the rest of the gas that is then sold at a distant location.

17
 Finally, and most significantly, the parties' decision to assess royalties on

"residue gas" shows that they never intended for royalties to be paid on gas consumed

in the treatment and processing steps. While "residue gas" is not defined in the royalty

agreement, it has a well-defined meaning in the industry. Residue gas means “[g]as

remaining after processing in a separator or other plant which removes liquid

hydrocarbons contained in the gas when produced.”13 By definition, then, any

volume of gas that enters a separator or plant is reduced by the time it comes out of

the separator or the tailgate of the plant.

This reduction in volume is the key to understanding the parties' agreement on

gas used as fuel. The parties' decision to base royalty payments on gross proceeds

received for "residue gas" is a designation of the volume of gas on which royalties

would be due: namely, the volume of gas leaving a separator or processing plant.

Because the parties had a sophisticated understanding of oil and gas operations, they

knew that the volume of gas would be reduced between the mouth of the well and the

exit, or "tailgate," of a processing plant due to the loss of the liquid hydrocarbons

13
Williams & Meyers, Manual of Oil & Gas Terms, 835 (14th ed. 2009). Accord Amerada
Hess Corp. v. Conrad, 410 N.W.2d 124, 131 (N.D. 1987) (citing 8 Williams and Meyers, Oil and
Gas Law, Manual of Terms, at p. 528 (1984)); Read v. Britain, 414 S.W.2d 483, 487 (Tex. Civ.
App.— Amarillo), aff'd, 422 S.W.2d 902 (Tex. 1967).

18
removed and sold, the loss of gas used to run compressors and gathering equipment,

and other shrinkage.14

The parties could have very well specified that royalties would be paid on gross

volumes. They chose instead to use gross proceeds, and to tie the calculation of

proceeds to the sale or other disposition of the volume of gas leaving a tailgate or

separator outlet after processing. By choosing that measurement method, the parties

agreed that no royalty is due on any natural gas consumed or used as fuel in any

operation prior to that point. Consequently, the parties never intended for royalties

to be paid on gas consumed in the preliminary steps required to make the gas

marketable.

Harrison will contend that our reading makes the language requiring royalty

payments on fuel gas meaningless. That is not at all the case. As one example, the

provision would apply to a lessor's use of gas. It is not unusual for lessors to ask to

use gas produced from their land as fuel for heating their homes, running equipment,

etc. In exchange, the lessor might accept a lower royalty or grant an easement. The

14
See generally Santanna Natural Gas Corp. v. Hamon Operating Co., 954 S.W.2d 885, 889
n. 8 (Tex. App.— Austin 1997, pet. denied) ("Gas accounting is difficult because gas volumes and
energy content fluctuate from day to day and a certain amount of volume shrinkage in the pipeline
and plant is normal.").

19
value of the lesser royalty, or the value of the easement, would be the measure of the

royalty owed by HighMount for fuel gas under paragraph 4(e).

The choice between the parties' competing explanations of the fuel gas

provision is stark. Harrison's reading, which focuses solely on a single sentence in the

agreement divorced from context, and which ignores the definition of the word

"proceeds" in that sentence, runs contrary to the proper task of interpretation. Courts

must give effect to the expressed intent of the parties' agreement as a whole, rather

than interpret one provision in isolation.15 “Courts must be particularly wary of

isolating from its surroundings or considering apart from other provisions a single

phrase, sentence, or section of a contract.”16

By contrast, HighMount's reading of the fuel gas sentence squares with the

agreement as a whole: it comports with the overall intent of the parties to

proportionately share post-production costs; it gives meaning to the term "proceeds"

in the fuel gas sentence; and it finds support in the parties' decision to base "gross

proceeds" on "residue gas" remaining after separation, treatment, and other gas loss.

15
See Royal Indem. Co. v. Marshall, 388 S.W.2d 176, 180 (Tex. 1965); Forbau v. Aetna Life
Ins. Co., 876 S.W.2d 132, 135 (Tex. 1994).
16
Forbau, 876 S.W.2d at 133.

20
 Accordingly, the court must reverse the trial court's ruling in Harrison's favor

and render a decision that the parties' royalty agreement does not require royalty

payments on gas used as compressor and gathering fuel.

B. Because the majority of the natural gas from the Subject
Interests is compressed "downstream" from components of a
"central facility," HighMount's compression charges are
permissible "Marketing Costs" under the royalty agreement.

The trial court’s other ruling held that HighMount was not allowed to deduct

gas compression charges from Harrison's royalty payments. HighMount deducts those

charges pursuant to two interrelated provisions of the agreement. The first provision

is found in the "General Terms" section and allows HighMount to deduct up to 10¢

per MCF for "Owners' royalty share of Producer's monthly Marketing Costs." Appx

B ¶ 7. The second provision is the definition of "Marketing Costs," which reads in

relevant part:

"Marketing Costs" shall mean:

(i) the reasonable, capital costs of property actually installed
by Producer or an affiliate of Producer after the Effective Time, which
property:

* * *

(b) is required to be installed downstream from a central
facility in order to deliver gas produced from the Subject Interests
to a gas transmission line or otherwise to a market; and

21
 (c) is part of a facility to transport gas produced from the
Subject Interests from a central facility to a gas transmission line
or is part of a facility compressing or treating such gas as required
for deliver to such a gas transmission line; and [Appx B
(emphasis supplied)].

The Marketing Costs deductions HighMount takes are consistent with the

parties' agreement. There is no question that compressing the gas mutually benefits

the parties by making the gas marketable. It is equally clear that the compressors

were, in the language of the agreement, "required to be installed . . . in order to

deliver gas produced from the Subject Interests to a gas transmission line." Appx B.

But based upon the physical location of some of the compressors vis-a-vis other gas

treating equipment, Harrison found a sort of "gotcha" argument that appears to have

swayed the trial court.

Harrison's argument rests upon the language in the Marketing Costs definition

that requires a compressing facility to be "installed downstream from a central

facility." R 686, 749. While the trial court did not explain its ruling, Harrison's

primary argument17 for rejecting compression charges was that the compressors were

not physically located "downstream" from a "central facility," as the latter term was

17
Harrison's motion concluded with an accusation that HighMount failed to prove it built
the compressor facilities in accordance with the Marketing Costs definition. R 555. If Harrison, as
the movant, wanted to shift the burden of proof to HighMount, it needed to follow the procedure to
file a no-evidence summary judgment motion, which it did not do.

22
defined in the agreement. Therefore, in Harrison's view, compression costs could not

be deducted as Marketing Costs. To the extent the judgment below rests on this

argument, it is error because the record reflects, at the very least, a genuine

unresolved fact question, and at the most, a set of facts inconsistent with the trial

court's ruling.

A "central facility," from which compressors must be downstream, is defined

in the royalty agreement as follows:

"central facility" shall mean the final set of heaters, separators,
meters and tanks that are operated as a unit and into which production
from more than one oil or gas well on the Subject Interests is gathered
for final treating and measurement prior to delivery to a gas transmission
line owned or operated by a principal purchaser of gas in the Permian
Basin. [Appx B ¶ 2].

With this definition as the touchstone, the evidence submitted to the trial court to

explain the location of the compressors at issue consisted solely of a diagram of DP6,

and brief statements in two expert reports. But even this limited information

demonstrated that the rich gas did qualify for the Marketing Costs deduction even

under Harrison's argument.

The opinion from Harrison's expert, Don Rockwell, is the starting point

because it makes HighMount's case. R 560. Rockwell looked at the diagram of DP6

and apparently missed the fact that there are two different gas inlets. Without

23
distinguishing which gas stream he was addressing, Rockwell explained that the gas

is compressed at DP6 for delivery to a high pressure gas line. Based on that fact he

opined that because the gas underwent additional treatment after leaving the

compressors, the compressors were not downstream from a central facility:

4. Once the gas leaves the compressors, it then goes through
other vessels on the facility, such as a filter separator, an eight-inch
discharge meter, an amine contactor, a heat exchanger, a recovery
separator, and a dehydration tower, before it flows to sale. Thus,
downstream from these compressors are a series [sic] heaters, separators,
meters, tanks and other vessels, where the gas is further treated and
eventually sent to market. From my understanding of the Royalty
Agreement, none of these compressors are downstream from a central
facility, as that term is defined. [R 561].

The upshot of his analysis is telling. Rockwell concludes that because the gas

flows through other treatment devices after being compressed, it can't be downstream

of a central facility. By that reasoning, if the compressors are the last stop for the gas

after going through other treatment devices but before it flows on to a third-party

pipeline, the compressors are downstream from a central facility.

HighMount's expert, Allen Cummings, recognizing that there are two streams

of gas flowing into DP6, reached just that conclusion. Observing that the definition

of a "central facility" does not include any reference to compressors or compression,

he pointed out that the compressors at DP6, by definition, cannot be part of a central

facility. R 753-54. He concluded, therefore, that because the compressors of the rich

24
gas, unlike the lean gas, are located "downstream" from the other facility components

that operate as a unit, the compression charges for rich gas satisfy the Marketing

Costs definition in the royalty agreement. Id.

Cummings's conclusion is confirmed by the flow chart put into evidence by

Harrison's expert, Don Rockwell. See R 772, 775. The print on the chart is so small

that it is difficult to follow the path of the gas as it flows through the facility. To aid

the Court's understanding of the schematic, HighMount highlighted the 20-inch line

through which the rich gas flows, and the 8-inch line through which the lean gas

flows, in different colors to make it easier to follow the path followed by the gas, and

added colors for the other processing equipment on DP6 as well. See R 752, Appx D.

As one can see from the diagram, the compressors for the rich gas are downstream

from any other equipment, and are the last processing step for that gas prior to

delivery to a gas transmission line.

Accordingly, by Harrison's own argument, the rich gas is eligible for the 10¢

per MCF charge for Marketing Costs. Because the trial court's judgment makes no

distinction between the funds that HighMount owes to Harrison on lean gas versus

rich gas, the trial court's summary judgment must be reversed and the case

remanded for further factual findings on the quantity of gas qualifying for the

Marketing Costs deduction.

25
 CONCLUSION

The drafters of the royalty agreement went to considerable effort to narrowly

circumscribe the post-production costs that the parties would share. In deciding which

costs would qualify, the drafter's litmus test was mutual benefit: where the treating

or processing undertaken would improve the gas for the benefit of both parties, the

cost was to be shared. Nevertheless, on the basis of a single sentence in the

agreement, the trial court concluded that the parties did not intend to share fuel gas.

The trial court's misreading of that sentence ignores the meaning of the term "gross

proceeds," misses the import of paying royalties on "residue gas," and stands at odds

with the ethos of the agreement as a whole.

As for the question of marketing costs, Harrison's own expert’s position on the

concept of "downstream" compression demonstrates that HighMount is allowed to

deduct costs on the rich gas stream flowing through DP6.

PRAYER

For the reasons presented, HighMount asks the Court to (1) reverse the trial

court's summary judgment, (2) render a decision that HighMount has no obligation

to pay royalties on gas it uses for compression and gathering fuel, (3) hold that

HighMount is entitled to charge up to 10¢ per MCF for Marketing Costs for rich gas,

26
and (4) remand the case to the trial court for further findings on the amount of rich

gas subject to that marketing charge.

Respectfully submitted,

FARNSWORTH & vonBERG, LLP

By: /S/ T Brooke Farnsworth
T Brooke Farnsworth
State Bar No. 06828000
Bennett S. Bartlett
State Bar No. 01842440
333 North Sam Houston Parkway
Suite 300
Houston, Texas 77060
Telephone No. (281) 931-8902
Facsimile No. (281) 931-6032

ATTORNEYS FOR APPELLANTS

27
 CERTIFICATE OF COMPLIANCE

The forgoing brief was generated by computer-based word-processing
software, and I certify that the total number of words counted by that software,
excluding those parts of the brief to be excluded under Rule 9.4(i), totals: 6,419.

/s/ Bennett S. Bartlett
Bennett S. Bartlett

CERTIFICATE OF SERVICE

I hereby certify that a true and correct copy of the foregoing document was
served via e-service to the parties listed below on May 13, 2015.

Charles S. Kelley
ckelley@mayerbrown.com
Quinncy N. McNeal
qmcneal@mayerbrown.com
MAYER BROWN LLP
700 Louisiana Street, Suite 3400
Houston, Texas 77002
Facsimile: (713) 238-4703
ATTORNEY S FOR APPELLEES

/s/ Bennett S. Bartlett
Bennett S. Bartlett

28
APPENDIX A
 fa.5- 12/2/2014 616 02 PM
ChllS Daniel • Otstncl Clerl< Hams County
Envelope No 3354569
By CAROL WILLtAMS
l.J(/\ Filed 12/2/2014 6 16 02 PM

CAUSE NO. 2009-06060 ( b (p\
213
HARRISON INTERESTS, LTD., DAN J. § IN ml!! DISTRJCt cot RT OF
HARRISON Ill, AND BFH MINING §
LTD., §
§
Plaintiffs. §
§ HARRIS COUNTY, TEXAS
vs. §
§
§
HIGRMOUNT EXPLORATION & §
PRODUCTION, INC. AND DOMINION § 190rn JUDICIAL DISTRICT
OKLAHOMA TEXAS EXPLORATION & §
PRODUCTION. INC., §
§
Defendanu. §
§

FINAL JUDGMENT

THE COURT, having considered the parties' pleadings. including the cross-motions for

summary judgment, the summary judgment evidence attached thereto, the responses to the

summary judgment motions, and the arguments of counsel for Plaintiffs Harrison Interests, Ltd.,

Dan I. Harrison, TU and BFH Mining. Ltd. ("Plaintiffs") and Defendants HighMount Exploration

& Production LLC ("HighMount") and Dominion Oklahoma Texas Exploration & Production,

Inc. (collectively, the "Defendants.,). is of the opinion and has ruled that Defendants have

breached that certain Royalty Agreement, dated May 22 1 1990, the subject of tbis litigation, by

withholding payment of royalties for gas production used for fuel on those properties located in

Annexes I and 2 of the Royalty Agreement in Sutton and Edwards Counties, Texas (the "Subject

Interests'') and by assessing improper marketing costs on the gas volwnes produced on the

Subject Interests, a.s described in Plaintiffs' motions for summary judgment and more fully

below. IT IS FURTHER,

RECORDER'S MEMORANDU.M
This Instrument Is ol poor quehty
at the time of Imaging

843
 ORDERED that, pursuant to the Court's signed orders ofJune 4, 2014 granting summary

judgment in favor of Plaintiffs as to Plaintiffs' Motion for Summary Judgment for Royalties on

Gas Used for Fuel and as to Plaintiffs' Motion for Summary Judgment for Reimbursement of

Marketing Costs, Defendants are required (i) to pay royalties to Plaintiffs on all production used

as fuel on the properties to which the Royalty Agreement relates. and (ii) to remove any

marketing deduction as none is entitled lo be applied in light of the operations as they exist as of

the date of this judgment; it is FURTHER

ORDERED that Plaintiffs shall recover from Defendants all principals sums owed based

on improper royalty withholdings and inappropriate marketing deductions made on royalty

payments that were made (or should have been made) on or before November 30, 2014

(including a missed royalty payment in its entirety for the production month of August 2014

which is not the subject of this suit and may have been missed accidentally), in addition to

prejudgment interest (as provided for under the parties' contract) calculated at the Prime Rate (as

announced by Texas Commerce Bank-Houston, N.A.) plus two percent (2%) from January l,

2004 onward; it is FURTHER

ORDERED that, because Plaintiffs have incWTed the attorneys fees and coW1 costs in

filing the action to enforce its right of payment, they shall additionally recover these reasonable

and necessary attorneys fees and costs arising out of the prosecution of this matter, as provided

under Texas Civil Remedies and Practice Code § 38.001 (8) for actions in breach of contract. and

the parties have announced their stipulation that, through the date of entry of this judgment only,

the amount of such fees and costs that shall be payable by Defendants to Plaintiffs are $325,000,

plus costs in an amount ofSl 1,200.00; it is THEREFORE,

2

844
 ORDERED. ADJUDGED and DECREED that Plaintiff Harrison shall recover from

Defendants, either jointly or severally, the sum of $218,637.16 in principal damages for

reimbursement of improper marketing cost deductions; the sum of $68,063 .90 in principal

damages for reimbursement of royalties on fuel gas use; and the sum of $100,697.03 in pre-

judgment interest for payments that should have been made on or before November 30, 2014

under the royalty agreement between the parties, together with daily interest accruing on this

combined amount at the rate of $55.72 per diem each day thereafter until entry of this judgment.

Accordingly, Plaintiff Harrison shall recover the total of $387,398.09 from Defendants. either

jointly or severalJy. in principal damages and interest, plus the additional accrued pre-judgment

interest; it is FURTHER

ORDERED, ADJUDGED and DECREED that Plaintiffs Dan J. Harrison, 111 and BFH

Mining, Ltd., ~ shall recover from Defendants. either jointly or severally, the sum of

$6,641 .27 in principal damages for reimbwsement of improper marketing cost deductions; the

sum of $2,202.07 in principal damages for reimbursement of royalties on fuel gas use; and the

sum of $3,023.94 in pre-judgment interest for payments that should have been made on or before

November 30, 2014 wider the royalty agreement between the parties, together with daily interest

accruing on this combined amount at the rate of $1.71 per diem each day thereafter until entry of

this judgment. Accordingly, Plaintiffs Dan J. Harrison, III and BFH Mining, Ltd. shall each

recover the total of $11,867.28 from Defendants. either jointly or sevcraUy, in principal damages

and interest. plus the additional pre-judgment interest; it is FURTHER

ORDERED, ADJUDGED and DECREED that Plaintiff Harrison shall recover from

Defendants, either jointly or severally, the amount of $325,000 in reasonable and necessary

attorneys' fees and Sll.200 for disbursements for those fees and expenses incurred up through

3

845
November 30, 20141 and that, in the event of any further legal work necessitated by post-

judgment motions or practice, together with any legal work in successfully defending this

judgment on appeal 1 Plaintiffs will be pernlitted to recover their reasonable attorneys' fees and

expenses on further application in any additional amowus to be detemiined in the future by this

Court and all defenses to such additional amounts may be urged at such time; it is FURTHER

ORDERED. ADJUDGED and DECREED that Defendants shall pay post-judgment

compOlmd interest on the outstanding amounts due under the judgment pursuant to Tex.as

Finance Code § 304.002 from and after the date of entry of this judgment until such amounts are

paid in full, and such post-judgment interest shall accrue on all amounts required to be paid

hereunder and be payable at a rate of the Prime Rate (as aMounced by Texas Commerce Bank-

Houston, N.A.) plus two percent (2%) compounded annually from the date of entty of the

judgment until the amounts required hereunder are satisfied; and it is FURTHER

ORDERED! ADJUDGED and DECREED that Defendants shall bear all costs of court.

All writs and processes for the enforcement and collection of this judgment may issue as

necessary. The parties agree and acknowledge that Harrison has not been paid the sum of

$31,988.41 in principal for the missing royalty check for August 2014 production, which

HighMount will remit along with the December payment.

AU other relief sought and not expressly granted herein is DENIED.

SIGNED this I.it... day of December 2014.

~~
4

846
AGREED AS TO FORM
AND STIPUU TED AS TO FEES AND EXPENSES (through Nov. 30, 2014):

By:ls/ Chnrle.5 S. Kelle11
Charles S. Kelley
MA YER BROWN LLP
700 Louisiana St., Suite 3400
Houston, Texas, 77002
Tel. 713-238-3000
Fax. 713-238-4634 .

ATTORNEY FOR PLAINTIFFS
HARRISON INTERESTS, LTD., DAN
J, HARRISON, III AND BFH
MINING, LTD.

By: /.VT. Brooke F'arn.\-wm•/h
T. Brooke Farnsworth
Farnworth &. vonBerg
333 North Som Houston Pkwy
Suite 300
Houston. Texas 77060
Tel. 281-931-8902
Fax. 281-931-6032

AITORNEY FOR DEFENDANTS
.HIGHMOUNT EXPLORATION A
PRODUCTION LLC AND
DOMINION OKLAHOMA TEXAS
EXPLORATION & PRODUCTION,
INC.

s

847
APPENDIX B
 R0¥AJ.'l'Y 1.GBE£MEHT

This Royalty Agreement is made and entered into to be
eff ect:.iva all of th9 Effective Time stated below, by and between
!L\R?!SON INTERESTS, LTD., a Texas limited partnership, DAN J.
HARi- Oar.DI!:~ ~
2050 90 56S CCSO & RGN'O Ry Co. Edwards
36 &: 825 91 566 CCSD & RON'O Ry Co. Sunon & Edw1rds
3S 105 573 CCSD & RONO Ry Co. Sutton
1714&2032 106 573 CCSD & RGNG Ry Co. Sunoo 4' Edwards
1595 107 574 CCSD & RONG Ry Co. Edwards
2506 112 576 CCSD de RONO Ry Co. Edwards
33 & 828 113 571 CCSD & RONO Ry Co. S1.1ttoll &. Edwards
1180 114 577 CCSD & RONO Ry Co, Sutton
34 115 578 CCSD & RONG Ry Co. Sutton
1185 126 583 CCSD & RGNG Ry Co. Sutton
31 127 584 CCSD & RONO Ry Co. Sutton
32 207 624 CCSO & RONG Ry C.O. Sutton
ms &2049 208 624 CCSD & RONG Ry Co. Sutton &: Edwards
178 209 625 CCSD & RONG Ry CO. Edwards
2673
2602 El 2
wy.2 214
214
61:7
61:1
CCSD & RONG Ry CO.
CCSD &. RONG Ry Co.
Edwards
Edwards
28 Ir, 781 21S 628 CCSD ct RONG Ry Co. Sutton & Edward5
1179 216 628 CCSD & RGNO Ry Co. Sutton
782 219 630 CCSO &: RONG Ry Co. Edwards
Bein~ tbe lan4s covered by that ce1taia deed from Oscar Appelt et ~ as gr_an1or, 10 D. 1.
Hamson. dated Se~tcmber 17, 194S of record in Vohune 42, page 360 of the Deed Records
of Sutton Couniy, Texas, and in Volume JS, Page 4l9, Deed Records of Edwards County,
Texas, as reswveyed.
Said lands being subject to that cenain Boundary Agreement by and between O. J.
Harrison and W. L Miers dated January 24, 1956, of record in Volume 40, Page 369, Deed
Records of Edwards Couoty, Tcxa.s.

i"
3
j

1
J
l
l
NI of Sucve~ 8l(A-63) and 116 (A-1647), originally granted lo the CCSD &. RONG Ry.
Co., located in Sutton ounty, Teus.

jl/1U1lo/lloAI
 l:N!IZJ: :z
(To RoJ•ltJ A()'re. .ent•

OESCRIP1ION or t,EAses

1. Oil, qas and ~ineral le••• dated Novelllll•r 5, 1971, recorded in
Voluae z-17, paqe 256 ot the Hiso•ll&neoua Records or Edward•
County, Texas, froa W.L. Miers and vite, Martha Miera, aa
le•aor, to R.c. Roberta, a• la••••• coverinq survey 4 (A-
1250), cert. Ho. 4, Menu·d County Sobool L4nd, Oriqinal
Grantee, SAVB and EXCEPl' 320 acre• committed to the Nortl\
Aln•rican Royal tiG·S, Ino. No. :i Miera '"'" Well and 320 acres
committed to th• North .a.i.erican Royaltiea, Inc. tlo. l 1t4•
Well, containing a total of 4 1 428.4 acree, more or les•,
sW>ject: to the tallowing r•l•a••• as to sl.lrfac• ar••• and
subaur!ace depths:
a. Partial r•l•H• Of oil, gaa and ainaral l•••• dated April
1, 1980, racordad in Volwoe .z-29, page 762 or th•
Hiscellaneoua Deed Record• of E.dward• County, Toxa•1 and
b. Partial r•l•••• ot oil, qaa and mineral leas• dated
February 24, 1982, recorded in Volume Z-32, pag• 864 of
th• Miscellaneous D•ed Record• of Edwards County, Texas.
2. Oil, gas and 1dneral lease dated November 18, 1971, recorded
in Volume 92, paq• 156 ot th• Deed R•corda ot Sutton County,
Texas, trom Larmon L. cox and wit•, Paarl cox, aa le.saor, to
R.C. Roberts, as les•e•, only i.naofar as such lea•• covers the
Northeast Quarter (NB/4) ot Section 70 (A-1039), ccso ' 'RGNG
Railway co. survey, and the Soutllweat (SW/4) ot Section 70 (A-
1672), ccso" RGNG Railvay co. survey, botll in Sutton County,
Texa•.
l. Oil, qas and mineral lease dated June 16, 1971, recorded in
VolU111e 90, paqe 23!! of the Deed Record• ot Sutton county,
Te1Ca11, from L.L. HoCandle••• et al, a• le••or, to North
.!Uaer:ican aoyaltiea, Inc., aa le•see, only inaofar ae such
lease covera the southeast Quarter (SE/t) ot Section 83 (A-
38), Cartiticat• 562, ccso and RGNG Railway co. oriqinal
Grantee, Sutton County, Texa•.
4. oil, 9a• and 111ineral lease dated June 20, 1972, recorded in
Volume 96, paqe 494 ot the O••d Recorda ot Sutton county,
Texa• fro• Harold c. Stuart and wit•, Joan Skelly Stuart, a•
lesaor, to North Alll•rican Royal ti••• Inc., a• les•-· only
insofar as such lease covers the south•a•t Quarter (SE/4) of
section Bl (A-l8), ccso and RGNG Railway co. survey, Sutton
county, Texas.
5. Oil, qas and mineral lease dated July 7, 1972, recorded in
Volume 96, paqe 497 ot tbo Deed Record• of Sutton county,
Texas, from Xirby Petroleum Co., as lessor, to North American
Royalties, Ina., as les•ee, only insofar as aucll lea•• covers
the Southeast Quarter (SE/4) ot Section BJ (A-38), CCSD and
RGNG Railway co. survey, Sutton county, Texas: and
6. Oil, qas and mineral lease dated July 19, 1972, recorded in
Volume 96, paqe 297 of the Oeed Records ot Sutton County ,
Texas trom Historical Preservation, Inc., as lessor, to HNG
oil Company, as lessee, only insofar as such lea- covers the
southeaat Quarter (Sl!:/41 Section 83 (A-38), ccso and RGNG
Railway co. SUJ."Vey, Sutton county, Taxa:11.
The interest in tile Uve (5) leaaea listed above as item
nu'IDbers 2 throuqh 6, inclusive, is limited to depths from tne
surface down to so !~et below the base of th• · canyon Sand
Formation.

]
tl
l
~
1. Oil, qas and ~inaral lea9• dated June 1, 1972, recorded in
Vol um• 96, paq• 62 o! the Oeod Reco~d• or Sutton County,
Texas, rrom Harvey ~. Heller and Kartey A. Heller, Jr., as
lessor:, to Dan J. Harrison, Jr., aa le••••· coverinq Section
83, (A-697) , Certit'icat• Ho. 0/6J2, Block 14, TWNG Ry. Co.
survey, sutton County, Texa•.

Sl357(2)
 ANNW[3

(to Royalty /\gre~ent)

A. All insO"l1111ents described below are dated May 22, 1990.

B. The grancee or assignee in each insaument is Meridian Oil Production Inc.

C. References below to volume and page recording dara IU'e to w Deed Rei:ord.s
of Sucron County, Texas, and to the Deed Records or MiscellaneoU$ Deed
Records of Edward County, Texas, as indicated below.

O. "M/A" means not applicable.

Recording Pata
Edwards Sutton
Gmntor!Assimo[ ~ f&!mlx
1. SpeciaJ Wa.tTanty Harrison lnterests, Ltd., Vol: Z-47 Vol: 244
Deed (Minerals) Dan J. Harrison Ul and Page: -MS Page; 48
Bruce P. Harrison. Misc. Deed
R.ecords

2. Special Wammty Dan J. Harrison m Vol: Bl Vol: 244
Deed (Surface) Page: 791 Page: 37
Deed Recordll
3. Special Warnuny Bruce F. Harrison Vol: Bl Vol: 244
Deed (Surface) Page: 785 Pase: 26
Misc. Deed
Records

4. Special Wanamy Dan J. Harrison Ill Vol: N/A Vol! 243
Deed (State Tract) Page: N/A Page: 389

5. Special Warranty Bruce F. Harrison Vol: N/A Vol: 243
Deed (State Tract) Page: N/A Page: 396
6. Assignmmr Harrison Interests, Ltd., Vol: Z-47 Vol: 244
Dan J .. Harrison !U and Page: 430 Page: 12
Bruce F. Hamson Misc. Deed
Records

7. Quitclaim Deed Harrison Interests, Ltd., Vol: N/A Vol: 244
Dan J , Harrison Ill and Page: N/A Page: B
Bruce F. Harrison

Signed for Identifkation Purpo$es:

ME~ OlL PRODUcnON INC. HARRISON INTERESTS, LTD.

ar-.hhE. ~ . ,.
Title: ~A • "· t:->_
,(~di..,~,,-
'"Name:
Title:
ux J. naqison
General Partner
H.~t1,.1

,
 ROYALTY AGREEMENT

2. Definitions.

“central facility” shall mean the final set of heaters, separators, meters and tanks that
are operated as a unit and into which production from more than one oil or gas well on the
Subject Interests is gathered for final treating and measurement prior to delivery to a gas
transmission line owned or operated by a principal purchaser of gas in the Permian Basin..

“gross proceeds” shall mean the entire economic benefit and all consideration in
whatever form received by or accruing to Producer or an affiliate of Producer, including but
not limited to sales proceeds or proceeds or benefits of an exchange, prepayments for future
production, reimbursements for severance taxes or for other taxes or costs, settlements or
payments for the release or amendment of a sales contract or arrangement, and take-or-pay
payments or settlements and the like, and any insurance proceeds from lost or destroyed oil
and gas, provided that “gross proceeds” shall not include any fee or charge for services
(transportation, compression, treating and the like) relating to gas produced from the Subject
Interests after such gas leaves the Subject Interests. In the event Producer transports, or
causes to be transported, gas production from the Subject Interests on a gas transmission line
to a market or sale “gross proceeds” for such gas shall be determined after deducting any fees
or charges incurred by Producer from the owner of the gas transmission line for such delivery
or transportation to such market or sale; such fees or charges shall be for transportation of
gas after it leaves facilities to which Marketing Costs, if any, relate and shall exclude fees or
charges of Marketing Costs.

“Marketing Costs” shall mean:

(i) the reasonable, capital costs of property actually installed by Producer
or an affiliate of Producer after the Effective Time, which property:

(a) is depreciable for purposes of the Internal Revenue Code of
1986, as amended; and

(b) is required to be installed downstream from a central facility
in order to deliver gas produced from the Subject Interests to a gas
transmission line or otherwise to a market; and

(c) is part of a facility to transport gas produced from the Subject
Interests from a central facility to a gas transmission line or is part of a
facility compressing or treating such gas as required for delivery to such a gas
transmission line; and

(ii) charges made by a third party that is not an affiliate of Producer
 directly attributable to property actually installed after the Effective Time, which
property:

(a) is installed downstream from a central facility in order to
transport gas produced from the Subject Interests to a gas transmission line
or otherwise to a market; and

(b) is part of a facility required to transport gas produced from the
Subject Interests from a central facility to a gas transmission line, or is part
of a facility compressing or treating such gas as required for delivery to such
a gas transmission line.

As to property actually installed by Producer or an affiliate of Producer, Marketing Costs
shall be calculated as a monthly charge on a per MCF basis for the facilities to which the
Marketing Costs relate, with such Marketing Costs amortized on a straight-line basis for the
expected life of such facilities and based on the entire design capacity throughput of the
facilities. Marketing Costs charged to Producer by a third party shall be the rate actually
charged to Producer.

4. Gas.

(a) As to gas produced or to be produced from the Subject Interests under a Short
Term Sale, the royalties shall be Owners’ royalty share of the gross proceeds for the first sale
or disposition of the gas from the Subject Interests, provided that such royalties never shall
be less than Owners’ royalty share of the aggregate sum derived by multiplying the Spot Gas
Price of such gas for the month or months covered by the Short Term Sale by the respective
volumes of gas sold in such month or months under the Short Term Sale.

(b) In the event Producer intends to make gas produced or to be produced from
the Subject Interests subject to a Long Term Sale, ...

(c) If the gas produced from any well situated on the Subject Interests shall
contain in suspension condensate, gasoline or other natural gas liquid hydrocarbons that
economically can be separated from the gas by the installation by Producer of traps,
separators or other mechanical devices, then Producer shall install such devices on the
surface of the Property, and Owners shall receive royalty on the condensate, gasoline or other
natural gas liquids so recovered in accordance with the terms of paragraph 3 of this Royalty
Agreement, together with royalty on the residue gas in accordance with the terms of
paragraphs 4(a) and 4(b) of this Royalty Agreement.

(d) If gas or casinghead gas or separated gas resulting from field separation
produced from the Subject Interests is processed at any location by or for the account of
Producer, or by or for the account of any affiliate of Producer, for the recovery and sale or
other disposition for value of liquid hydrocarbons, helium, carbon dioxide, sulfur, or any
other elements of the gas steam, then in lieu of royalties on gas provided in paragraphs 4(a)
 and 4(b), the royalties shall be Owners’ royalty share of the gross proceeds less Owners’
royalty share allocable portion of the reasonable, direct costs (excluding amortization and
depreciation on pipeline and plant investment and direct overhead associated therewith) of
processing such gas in the plant for the recovery of such liquid hydrocarbons, helium, carbon
dioxide, sulfur and other elements, and the royalties on the residue gas resulting from such
processing operation attributable to gas produced from the Subject Interests shall be in an
amount and determined as provided in paragraphs 4(a) and 4(b) above; provided, however,
that in the event liquid hydrocarbons, helium, carbon dioxide, sulfur or any other elements
of the gas stream are recovered and sold separate from the basic gas stream as contemplated
in this paragraph, the total royalties paid to Owners on such production (after deduction of
the above costs) never shall be less than would have been paid to Owners if the liquid
hydrocarbons, helium, carbon dioxide, sulfur, or any other elements of the gas stream had
remained in, and been sold as, part of the basic gas stream.

(e) Owners shall receive their royalty share of the gross proceeds for gas used or
utilized on or off the Subject Interests, such as gas used for fuel.

7. General Terms. The following general terms shall apply to the royalties covered
by this Royalty Agreement.

(a)...

(b) All royalties shall be determined and delivered or paid to Owners after
deducting therefrom the following costs:

(i) as to gas produced from the Subject Interests, Owners’ royalty share
of Producer’s monthly Marketing Costs for such gas; however, for purposes of this
paragraph 7(b), Producer’s monthly Marketing Costs (whether actually incurred by
Producer or an affiliate of Producer or charged to the Producer by a third party) shall
not exceed ten (10) cents per MCF and shall be charged only as to gas production put
through the facility for which the Marketing Costs are charged; and

(ii) taxes applicable to Owners’ royalty share of production.

Owners’ royalties shall bear no other costs or expenses of any kind:

(g) In the event that Owners’ royalty share of gas is not committed to a Long
Terms Sale in accordance with the provisions of this Agreement, then at any time and from
time-to-time Owners may elect to take Owners’ royalty share of gas production in kind and
use or market same for their own account or to elect to deem royalty percentage of gas as not
being produced, to the end that Owners’ share of production is stored and covered under the
Balancing Provisions provided below.
APPENDIX C
I

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583
APPENDIX D
 - >:____

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