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

Opinion

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,

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

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

A. By deeds ot even date herewith and described in Annex 3 hereto (the "Deeds•), Owners have sold and conveyed to Producer all of Owner1• interest in the Property exceptin9 and reserving to Owners a 5\ of 8/8 perpetual nonparticipating royalty interest. a. By assiqrunen~s of even date herewith and de•cribed in Annox l hereto (the "AaaigflJ!l•nts"), Owners also have sold and conveyed to Producer all of Owners' intere•t in the Laaaas excepting and reserving to Owners a 5\ of B/8 overridinq royalty interest in each of the Leases. c. Owners and Producer wish to set out in this Royalty Ag ree ment the terms and provision• that will govern administration and payment ol such royalty interests, which terms and provisions are in addition to any general terms and prov isions stated in the conveyances made to Producer.

NOW, THEREFORE, for sufficient value received by each, and in consideration of the covenants contained herein, Owners and Producer aqrae1 1. Agree~ent. Thia Royalty Agreement shall apply to those perpetual nonparticipatinq royalty interests (the "Nonparticipating Royalties") in the Property created by exception and reservation to Owners in the Deeds and to those overr1dinq royalty intareu:1 (the "OV&rridea •) in the Lease• created by exception and reservation to Owners in the Asai9nments. The ter111a and provi1ion1 of thil Royalty Agree~ent shall control and qovern over any contrary or inconsistent ter111s or provisions of such conveyances. 2. Oefinit1ons. For purposes of this Royalty Agreement, the followinq term~ shall have the following meanings: • affiliate o f Producer " shall mean any individ1.1al, corporation, joint venture, partnership or other entity or organization controlling, controlled by or under co111mon control with Producer (the concept of control maaninq the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of anot·har) whether throuqh O'Wnarship of voting secu:t'itii;u, by contract or otherwise. "central facility• shall mean the final set of heaters, separators, meters and tanks that are operated as a unit and into which production from mo~a than one oil or gas well on the Subject Interests is gathered for final treating and measurement prior to delivery to a qas transmission lin• own•d or operated by a principal purchaser of gae in th• Per11\ian aa11n. "GQVernment.ol Rggul41:J,~mo" shall mean all laws, ordinances , statutes, code•, rules, regYlations, orders and decree• of the United Stat•• of All\erica, the State of Te xas, the Texa1 Railroad Commission, tdwards County, Sutton county, or any other political eubdivision in which th• Subject Int•r••t• are located, and any other political subdivision, aqency or intt~entality exerci1in9 jurisdiction over Owners, Producer or the Subject Interests. "grou proceeds• shall mean the entire economic benefit and all consideration in what•ver form rec•ived by or accruinq to Producer or an affiliate ot Produ~er, including but not limited to 1ale1 proceeds or proceed• or ben1tie1 of an exchang• 1 prapayment• for future production, r11Jnbur•e~nt1 tor severance taxe1 or for other tax.a or co1t•, ssttlemant• or piryment1 for th• release or iunendment at a s•l•• oontr&ot or arran9ement, and take-or-pay p1yinent• or settl•~ent1 and the like, and any 1naura~• proce1d1 fro• lost or de•troyed oil and ga•, provided that •gro•• proceed•" shall not includ• any tee or charqe for services (c:i:an•portation, compr•••ion, trwatin9 and th• like) rtlatln9 to 9ae produced from th• Subject Int•r••t• after such gu leave• the Subject Intere1t1. In th• event Producer tran1port• , or cause• to be transported, gaa production from the Subject Intere•t• on a qas tranamia1ion lin• to a market o:i:- !tale •qro11 proceeds• f or such qa1 shell be determined after deduc..:inq any t••• or charges incurred by Producer from the owner of the ga• trana111111aion line for such dalivary or transportation to such market or sale; such !eea or charge• shall be for traneportation of ga• atter it leavee facilit1e• to which Market1n9 Costs, if any, relate and shall exclude fee• or charges of Mark•tinq Costa. •Long Taoa Sale• shall mean any contract, agreement, arrangement or exchange concerninq dispo11t1on of production fro~ the Subject Intersata for a term greater than twelv~ (12) months. "tlarkel:ing Cosu• shall munz (i) the reasonable, capital coat• of property actually installed by Producer or an affiliate of Producer after the gffectiv• Tim•, which propertyz (a) is depreciable for purpo••• cf th• Internal Revenus Code of 1986 1 o• a~anded, and (b) is required to be installed downstream from a central facili ty in order to deliver qu produced from the Subject Intereet.s to a gas t ransmission line or otheJ;Wise to a market1 and (c) is part of a facility to transport gas produced from the Subject Interests from a central facility to a gas transmission lln• or is part of a facility compressing or treating such gas as required for delivery to such a qas transmission line; and (ii) char9es made by a third party that is not an affiliate of Producer directly attributable to property actually installed after the Effective Time, which property 1

2 .-. (a, is installed downstream from a central facility in order to transport ga• produced trom tha Subject Interest• to a ga• transm1ss1on line or otherwise to a market1 and (b) is part of a facility required to transport ga1 produced from the Subject Interests from a central facility to a gas transmission line, or is part of a facility compressing or treating such gaa as required for delivery to such a gas transmission line. As to property actually installed by Producer or an affiliate ot Producer, Marketing Costs shall be calculated aa a monthly charge on a par MC~ ba•is for the facilit1e• to which the Marketing coats relat•, with such Marketing Coats amortized on a straight-line basis tor the expected life of such facilities and based on the entire da•iqn capacity thrcu~hput of the facilities. Karketin; Costs charqad to Producer by a third party shall be th• rate actually charqed to Producer. ~ m••n• one thousand (1,000) cubic feet of gas, with •cubic feet ot qa1• meaninq the llJJIOUnt of qas contained in A cub.l.c foot of apace and at a base pre•sure of fourteen and sixty-five one-hundredth• (14.65) pounds per square inch absolute and at a base t•~perature of sixty degrees Fahrenholt. "mineral subatance;s• shall mean all mineral subn.ances or riqhts o ther than oil and qas, even if such substances occur so near the surface of the ground that they can or m~st be mined, produced or exploited by stripping away or otherwise destroying or substantially dl1turbing the surface of the qround, but excluding brick and cement clay, ground wat.er, subsuxfoce 11atar or water rights, top soil, !oam and ordi nary clay. By way of illustration, but not in limitation, such mineral subst.ances or riqhts that are "mineral r1qhte• for purpo•ea of thl• Royalty Agreement. shall 1ncluda sulphur, salt, coal, lignite, tar sands, heavy oil, tar, kero9en, uranium, vanadium, thori11111 and other f i s~onable substancee, all precious and bas• metals, gaothermal energy (including haatsd water and steam, entrained methane, hydroetatic preseur• and thermal energy), bauxite, iron ore, sand, gravel, rock, shell, caliche, lilllestona and any other mineral substance or right including near surf ace subatances used al road buildinq and road construction materials. , •oil and aH" shall mean any or all of t.he followinq1 oil, liquid hydrocarbons, gas, and their reepective c onstit~ent products, and any other subst1111Ces produced i n conjunction wi th oil and gas, or either of them; .::.stU..: shall mean oil, other l i quid hydrocarbons and their respective constituent pr od11cts, and any other aubstance producQd i n conjunction with oil; ~ shall mean qas and Lts constituent producta and any other substance produced in conjunction with gas. •oil or gas well " shall mean a vertical borehole with a wellhead, regardless of the number of horizontal drainholo9 that may be drilled or that exist connected to such vertical borohole, drilled and maintained for the purpose of producing 011 and gas. •quality • of oil and gas, mineral substances or subsurface r l qhts shall mean pby5ical characteristics of oil and gas, such as qrade, qravity, BTU content and the like, or physlcal characteristics of the mineral substances

l or subsurface rlqhts, and Goverl\lllental Regulations applicable to the oil and gas, mineral subs~ancas or subsurface rights, but not contractual terms. "Short Tgrm Sale" shall mean any contract, agreement, arrisnqement or exchange concerninq disposition ot gas from the Property tor a term of twelve {12) months or les1, provided that each renewal, extension or rollover of such an agreement for a new term of twelve (12} months or less shall be considered as a new ''Short Term Sale". "spot gas" shall mean gas sold under a Short Term Sale. "Sp9t Gas Price• as to gas for a calend.u month shall maim the arithmetical average of the t ...o highest index or average prices (or the two highest prices, if there aro no index or average price&) for the month atated ln availdble publication• thdt collectively etate monthly price• for spot qa.1 of~ered by at least five (5} principal purchasers of gas in the Perinian Baein for gae to be re1old or redelivared outside tho Per111ian Sa•in. Sellers and Purchaser agree that as of the effective Time the publication• used for thia purpose shall be •Inside F.£.lt.C. 1 11 Ga• Market Report.• 4tld the monthly survey distributed by Natural Gaa Clearinqhoqse, Houston, Texas, but other such publications shall be utilized or substituted at such time as "Inside P.E.ILC, '• Gaa Market Report" and such survey by Natural Gaa Clearinghouse cease to atate monthly prices for spot gas offered by at least five (S) principal purch..ssers at 91111 in the Permian Basin for gas to be resold or redelivered outside the Permian Basin, provided t hat i f there are no such publications or surveys of spot qa.s prices for ga~ produced from and delivered f.ro111 the Permian B4sin that are serviceable for t.he purpose contempla.ted herein, then "Spot Gas Pric•" ehall be the 4.rithtnetical averaqe of t.he two highest prices then beinq paid in the Pemi4n Ba.sin on such date or dates, for spot gas in arms- length sales between nonatfiliated parties, such prices to be appropriately adjusted ior any difterenceu in qiJality. "subrect Interests" sh!lll mean the Property and the Leeses. ••subsurface rights • shall mean the eight r.o store, allow or permit atora9• ot, in subsurface a..reas or formations of the Property, oil and qas or mineral substances that are not native to the Property, or wa1n:us, product• or ony other substance, and . riqht• to use or exploitation of caves or caverns in or under the P~perty, whether any or all of such rights are part of the surface estate or part of the mineral estate. "taxes• shall mean severance taxes, ad valore~ taxes and like t.sxes imposed by Gover!\11\ental Requlations. "trea'tinq ·• shall mean proces'il.i.nq of gas for the removal of contaminants such as water or hydroqen sulfide, and not proces1inq for the recovery for sale of constituents of the gas such as carbon dioxide, helium, hydrocarbon liquids and sulfur. 3. Q..U,. Royalties on oil shall be O~ners · royalty shdre of the oil produced or sold from the Subie<:t Interests, the same to be delivered at the wells to the credit of Owners into the pipeline or other facilities co which the wells may be connected, provided that Producer may from time to time purchase any royalty oil in Producer ' s possession and allocable to Owners ' royalty $hare, payin9 therlilfor the qross proceeds for so.lo or disposition of the oil from the Subject Interasts or use of utili:o.tion of such oil on or off the Subject: InterGsta, but: such purchases by Producer shall bw subject to termination at the discretion of Owners by providing written notice to Producer on or before the fifteenth day of the month prior to the month Ln which Owners qesire to terminate purchases by Producer. 4. (UU..

(a) As to gas produced or to be produced from the Subject Interests under ~ Short Term Sale, the royalties &hall be owners· royaley 11hare of the gross proceeds for the first sale or dispooition of the gas from the Subject Interests, provided that such royalties never- shall be lees than Owners• royalty share of the aqgreg&t• sum derived by multiplying the Spot Caa Pr1ca of such qas for the month or months covered by the Short Term Sale by the reapective volumes of qas sold in such month or months under tha Short Term Sale. (b) tn the event Producer intends to make qaa produced or to bo produced trom the Subject Int:ereet:s subject to a Lonq Term Sale, Producer shall notify Owners in writing of such intent prior to entering into such Lonq Tar• S.slo and provide 011nera with complete information reqardinq the buyer, price and other tarml and conditions of the propoead Long Te:rill Sale. Producer shall give Owners further written notice at such time as Producer proposes to execute the instrument docwaentinq the Lonq Term Sale, which notice shall include a complete, legible copy of such i nstrU111ant:. !Nnera a hall have tifteen ( 15) business days after receipt: of Producer·s notice containing a copy of the instrument proposed for docU111antin9 th• Lonq Term Sale in which to elect either to ratify same and co111111it Owners• royalty ahare of gas to the Long Term Sale or to reject same and take 011n•r• · royalty shar• of gas in kind, provided that as to all gas sold under a Lonq Term Sale to an af fl1 i ate of Producer, in addition to all other ~iqhts granted herein, 011ners shall have the riqht to receive their royalty share of such gae baaed on th• greater of (l) the qroH procead11 for disposition of the gas from the· Sgbje~t Interests or (ii) the Spot Gas Price of the gas so sold mult!plied by tha respective volwnea of gas sold each month under the Lonq Term Sale, provided that if at any time or from ti~• to time there does not exist a Spot Gas P.r ica tor qas disposed !rolft tha Subject Interests, then tha royalties shal l be the market value of such gas as established by reference to arms-l•ngth sales of gas in the Permian B~•in between nonaffiliat•d part.le•, appropr~tely adjueted for any differences in quality. I f Owner• e.lact to ratify the Lonq Term Sale, Producer sha.11 us• all roa11onanle efforts to havo ownors nal'llW

1' s I i term9 of paragraphs 4(4l and 4(bJ of this Royalty Agreement. (~) If gaa or casinghead gas or separated gas re.sulting frClDI field sepa.raticin produced frcim the Subject: Interests i9 processed at any location by or for the account of P·r oducer, or by or for the account• of any aff!lia.t-a of Producer, for the recovery and sale or other disposition for value of liquid hydrocarbons, helium, caxbon dioxide, sulfur, or any other elements of the gas stream, then in lieu of royalties on gas provided in paragraphs 4(a) and 4 (b) 1 t he royaltiee shall be owners• royalty share of the groa1 proceeds less Ovnera• royalty !!hare allocable portion of th• reasonable, direct costs (excluding amortization and dapreeiation on pipeline and plant investment and direct overhead associated theravith) of procassi.ng :!Inch ga11 in ths plant for tha recovery of such liquid hydrccarbosu, helium, carbon dioxide, sultur and other element•, and th• royalties on th• residue gas resulting from such proc•1•ing operation attributable to qa1 produced from the Subject Interests shall be in an a.mount and determined as provided in paragraph• 4(a) and 4(b) above; provided, however, that in th• event liquid hydrocarbon•, helium, carbon dioxide, sulfur or any other elements of the ga• streaJ11 are recovered and sold separate from th• ba1ic 9as stream as contemplated in this paragraph, the total royalties paid to Owners on such production (after deduction of the above costs) never shall be lesa than would have been paid to owners if the liquid hydrocarl:lOns, haliWll, 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 ot the gross proceeds for gas used or utilized on or off the Subject Interests, such as gas used for fuel. 5. Subpurfoce Riahts. On subsurface rights in the Property, the royaltia• shall be O'rlners' royalty share of the market value for use or utilitation of such riqhtl as established from time to tima by the greater of (i) arms-length sales or leas~e of such rights in the Perinian Basin between nonaffiliated parties appropriately adjusted for any differences in quality, or (ii} gross proceeds. ~. Mineral Substances. On mineral substances in tha Property, the royaltie• shall be owner•' royalty share of the market value of mineral sub1tancas sold from the Property or used or utilized off the Property for any purpos•, such ~alue to be establi~hed from time to time by the greater of (i) anis-len9th salee or leases of such substances in tha Permian Basin between nonaffiliated parties appropriately adjusted for any differences in quality, or {ii) gross proceeds. 7. ~eneral Terms. The following general terms shall apply to tha royalties covered by this Royalty Agreements (a) Producer will use its best efforts to obtain a market for and sell oil and gas and mineral substances produced from the Subject Interests 4t the maximUJll rate possible given prudent op•rating !ltandards . eroducer also will use its best efforts to qualify a ll oil and gas and other mineral sub.s tances or rights produced or sold from the Sub j ect Interests for the maximum legal sales price under Governmental Regulations, if applicable. (b) All royalties shall be determined and delivered or paid to owners after deducting therefrom the following costs:

6 (i) as to gas produced from the Subje~t Interests, Owner s • roy.slty !!hare of Producar's monthly ttarketinq Costs for such gas1 however, !or purposes of thJ.a par.s9raph 7 ( bJ, Producer's monthly Marketing Costs (whether actually incurred by Producer or an affiliate of Producer or cha·r qad to the Producer by a third party) shall not exceed ten (10) cants per MCF and sh.sll be charqed only as to gas production put t.hrough the !a.cil l cy for wl\J.ch the Harlcetinq Cosi:s are <:!hisrqed1 and (ii) taxes applicable to Owners' royalty share oi production. Owners• royalties shall bear no other costs or expenses of any kind, (c) (i) Accounting and paYll'ent by Producer to Owners of royalties from the production of oil shall be made on or before sixty (60) day1 after the end of tha calendar month in which the production occurred. (iii Accountinq and payaient to Owners of royalties from gal sold und•r a Lonq Term Sale that is ratified by Owners and in which Producer acts aa "Sellers• Representative• for purpoaa1 of receipt of qas sales proceeds dua to tha requirements of the buyer, shall be made on or before thirty {30) days attar Producer's receipt of gross proceeds from the sale of the 9as. (iii) Accounting and payment by Producer to Owners of royalties from the sale of gaa under a Short Tei:m Sisle or under a Lonq Term Sale to an affiliate of Producer shall ba 111'1da on or before sixty (60) days after th• end of th• cislandar month in which production occurs, provided that any deficiency in Producer's periodic royalty payments based on comparing Producer ' s 9rosa proceed• with applicable Spot Gas Prices under the pro~i sions of paragraphs 4(a) ~r 4(b) shall be paid to Owners on a calendar quarter basis, vithin thirty (30) days after Producer's receipt of owners• invoice therefor, unless Producer in good !aith disputes such invoic• by written notic• to owner• delivered within auch thirty (JO) day period, owners' failur• to supply sue~ an invoice shall not operate as a waiver or release of deficient royalty payments. (iv) Any royalties or other payments to owners provided for herein shall be paid to Owners at the address specified herein and shall accrue interest at the prime rate as announced from time to time by Texas Colllblerce Bank-Houston, N.A. plus two percent (2') from due date until paid (as to disputed amounts, interest shall be due as to the amount paid in settlement of the dispute, if any, with the du• date commencinq sixty (60) days after tha end of the calendar month in which the production to which the dispute relate• occurs), provided that such interest rate shall be spread, pro-rated, reduced or eliminated automatically to the leqal maximum rate in the event s/JJlle ever exceeds such maximum rate of interest to the end that this provision nave~ shall constitute Owners to be in violation of any Federal of State usury laws. Unless preempted by Federal law, the msximwa rate of interest shall be determined under the laws of the State of Texaa. Acceptance by owners , its

7 successors, agents or as!iqns, of royaitie! that are paat du~ shall not act as a waiver or e9toppel of its right to receive or recover interest due thereon under the provisions hereof. No tender or payment to Owners of a sum less than the total amount due to owners shall be dee'med a fu.ll settlement, whether by accord or satisfaction or otherwise, notwithstanding a check in tender of payment may contain language of settlement or accord printed or otherwise inserted thereon unless made and received in accordance with a separate written agreement executed by Owners and Producer. (d) Producer shall maintain complata and accurate book.a and records re9ardin9 the production, sale, use, utilizatlon or laaae of oil and 9as or mineral substances frorA tha Subject lnteras·ts and subaurfaee rights in the Property, and a• to Producer ' s Hark•tinq Cost•. Upon reasonable notice to . Prodl&Cer, Ownar• 1hall have th• right to examine and copy, at O!fn•r•' oxpen1e, all book1, racord1, documents, statement•, purchase agreements, sale agreements, operating agreements and any other inst:i:umants or records of Producer or an aff iliat• of Producer relatin9 to production volume•, qro•• proc . .d• of oil and qas or mineral sub•tancea fro~ or in the Subject Int•r•ats, and as to Producer's Marketin9 Costs. Suen ex41l'tination shall be conducted at the offices of Producer during no:rmal busin••• hours. Owners, or its agents or representatives, shall have the further right, at owners• sole risk and expense, to qo upon the Subject Intereats, one• each calendar year, to inspect the Subject Interests for reconciliation of owners' review of Producer's book• and records, and verification of the existence and extent of facilities related to Producer's Marketing Costa provided that owners shall not have accese to the rig floor and Owners shall not interfere with Producer's operations. Prior to Owners qoinq upon the Subject Interests, Owners ghall give Producer notice of their desire to go upon the 5ubjact Interests and Producer shall arrange a mutually agreeable time for inspection that is within thirty (30) days after Producer's receipt of said notice. Owners• notice shall include ~ description of those items it wishes to inspect. Each inspection by owners shall be limited in d~ration to . no lonqer than one (1) worlt day. Within a reasonable ·time not to exceed ninety ( 90) d.ay• after receivinq 11. written request from Owners, Producer also shall supply to owners complat:e and accurate c:oi;iie• of al.l agreamttnts respacting the sale or us• of oil and go.a, mineral substance• and subsurface right•. ( e) The terms and provisions of this Royalty A

B (9) In the event that Owners· royalty share of gas 1s not committed to a Long Term Sale in accordance with the provisions of this Agreement, than at any time and from tim••to-tim• Owners may elect to take Owner•' royalty share of ga• production in kind and use or market sa.m• for their own account or to elect to deem royalty percentage of gas as not being produced, to the end that Qlolnera • share of production is stored and covered under the Bal4ncinq Provisions provided below . Owne~!I shall make such election bI providing wd.tten not.lee to Producer prior to the £ tteenth day of the mont.h preceding the month in which Owners intend to take q1u1 in kind or t:o store g,•u1; likewise, Owners may terminllte the.ir: election to take gas in kind or to store 948 by providing written notice to Pi:oducar prior t:o the fifteenth day of th• inonth precodinq th• month in which Owner• cea~• to tak• 9a• in kind or store qae. In the event Owners elect to take its royalty in kind, i t shall have the turther right to u~• any of Producer's production, gathering and t:reatinq facilitie• and thar11by incur only the exp•n11• of Any separat• 111aterin9 device nacaa•ary for Owner•' separate marketing operation•. The Bab.n cinq Provi1ion• provided belo11 shall be in effect in the event Ownar• ever elect to 1tore 9a• under the provisions of thi1 paragraph, or in the event Owner11 ever produce a greater share of production than their royalty percentage due to their taking production in kind. Any possible aala• by a party of the othor party ' s share of production shall be only for such reasonable periods of time as are consistent with the roinimWll need• of the industry undor tho particular circum1tance•, but in no event for a period. in excoss of one (11 year, and at all timG• shall be subject to revocation at "i l by the other party. In the av•nt Owners elect to take production in kind, Producer shall transport, or use reasonable efforts to clluee to be transported, Owners• royalty share of production to a mutually agreeable point on Producer's or affil iate of Producer's, gatherin9 ayste~, for redelivery co Owners or Owners• agent, provided that Producer shall not be r equired to enter into new agxaements '!'ith third part.Les or to construct nav faoilitiaa to transport or cause transportation of owners' production. In the event Producer: ol: an affiliat.e of Producer so transports or causes to be transported gas for Owners, Owners shall pay the Karkatinq Costs for such transportation, if any, for use of facilities installed by Producer or an affUiate of Producer after the J?ffective Time, but not to exceed a charge of ten ( 10) cants per MCP for the CJ•• transported. In the event Producer cau1oa a third party to so so trlln•port gas for Owners under an a9reement then existinq bet:ween Producez: and thlld J?&rtY, Owner• shall pay the fee charqed to Producer by the third party,as t o the volume of Owners· gae eo traneportod. If Owne-1:11 cause a third party to transport owners' gas, owner1 shall be re•poneible for the fee charged by such third party. 8. Boloncinq Provisions, (a) Notvithstandinq anything to the contrary in this Royalty Aqreement, Lf in accordance vith the provisions hereof, either party hereto takes and disposes o f less than its percentaqe share of production dur i ng any calendar month, than the volume not taken by such party may be taken by the other party. (b) These Balancing Provisions shall apply separately to each cateqory established by Governmental Regulation for the purpose of re9ulatin9 or deregulating the price of production, i nc ludin9 but not li~itad to cateqories estl.lblished by the Natural Gas Policy Act of 1918 and

9 raqulatione or orders o! tne federal Enorqy Regulatory Coll\llliss1on or any $Uccessor or similar agency or CommUll ion. rn the event a cateqory is revised, the cateqory as revised shall be con•idered a nev and separate category. (C) The term "Cumu lative Underproduction• maans tho amount by which the cumulative volume of production taken by a paxty within a par~icular category J.s less than tho cumulac.J.ve volume such party wa1 entitled to take within 9uch category according to its percentage i nterest/ the tar111 "Cumulative Overproduction " means the amount by wl'lich tile cumulativs volume of production taken by a party within a category exceeds the cumulative volu111• that suoh party was entitled to take within such category accordinq to its percentage interest; tha term ·onderproducar" means a party credited w.1.th Cumula1;lva underproduction; t.he term ·ov•rproducer• means a p11rty charqed with Cumulative overproduction; and the torm "Make-Up Product.I.on• mean11 the volume taic.an by a party to make up Cwnulative Underproduction pursuant to Paragraph (&) below. (d) On or before nim1ty (90) day• after the end of each calendar month of production, Producer •hall furnish to owners a written statement showing for each category (i) tho total volu11• of production taken by eac:b party during such month and (ii ) the Cumulativ• Overproduc:tion or Cwnulative Underproduction, if any, ot each party a1 of the end of that month. (e) By giving written notice to Producer at least 15 d.?1ya before i:he baginnln9 of a calendiir month, a parey $hall be entitled to take during that month, in addition to it• full percentage interest share of produceJ.on, a volume of Maka-Up Produotion e.q ulll to it• cumulative Unde't'production, provided that to accol1111lodata such mak.. •up the other party shall never be required to take less i;han 7St of its ~rcentaqe interest share of production durinq the month, and provided that the right to take Make-Up Produc:1;ion shall be subordlnate to th• right of Producer to take i ts full percentaqe interest share of production from t ime to tiJU• to satisfy the d•livara.bility test requirements of any sales contract applicable to production from the Pxoperty. Make·UP Production volumes shall be applied aqainat Cuinulative Underproduction and Cumulative overproduction on a first-1n~t1rst-out ba•is. (f) If the parties have not achieved 11 volumetric balance in production in all categories upon a perinanent ceasai:ion of all production from th• Property, Producer shall furniah to Ovner• 11 statement showing the final Cumulative Overproduction and Cumulative Underproduction of each party by category, and the month and year in which it accrued. Within 120 days after receipt of Producer's statement, each OVerproducer shall furnish to the Undecproducar a statement showing th& value of its Cumulative overproduction for each category, based on the price the Overproduoer actually received fox the production i n a sala durinq tne month(s) in which the Cumulative overproduction accrued, lesa all payments made by the OverptQducer pursuant to Paragraph (h) below. For production sold by Producer, value for thia purpose shall be based on the provi11ions of tha foregoinq royalty reservationr for owners, value for this purpose shall be based on the price actually received by Owners. Baaed upon the statements furnished by Ove.rproducers, the net amount owed by or to each party for all cateqories combined shall be calculated by Owners and furnished to Producer in a final cash ba.lancinq statement.

10 (g) Within 120 day• after receipt of Producer's tlnal cash balancing stateme nt, the ovarproducer shall pay the Underprodue4r in accordance with the statement and ~ithout i nterest. To the extent any value used to calculate a cash ssttlement hereunder is subject to refund by the Overproducer pur9uant to Goverl\Jllental Requlation, the Underproducer shall, prior to payment thereot, agree i n writing to indemn.Uy the OVe:r:producer 11911.inst the Underproducer ' a proportionate part of any refund (including interest) which the Ovel;l)roducer shall be required to mako . Any party may challenge any volumes or values or amounts epecif i ed in any of th• statement• furnished under Para9ra~h (f) above, in th• Sil.Ille nia.nner and subject to the slllll• limitations as an invoice from a.n operator may b• challanqed under a AAl?L Hod•l Form Operatin9 Aqraament or the COPAS accouncing procedure thereto, using th• latest printed forms of same at the tilll• ot th• challanqa, lofithout alteration; it no auch printed fo:rra• ex.i•t at the tima of chAllenge, than the mo•t similar document• than in qanaral usa in tha oil and gae induat:ry shill be used. (h) Each party taking production shall pay or cause to be paid all production And oxa is• tax••, if any, on 9aa taken and sold tor its account under th.Li B4lano1ng Provi•ion. Horaovar, such party shall pay or oauea to be paid all royaltia•, overrid1nc;r royaltia• and other payments on production it is obligated by lav, by leas~ or by contract to pay. Eaoh party hereto aqrea• to lndamnify and hold harmlea1 tha Other partie• hereto against all claims, loas1H or U.a.bilitia.s arising out of its failure to fulfill such obligations. 9. Miscellaneous. (a) All eKhibits or annexes hereto are incorporated herein and by this reference made a part hereof. (bl There shall be no reoordation of thia Royalty Aqreement or ony mell\Orandum thereof, (c) Anr notice, co111111unication, request, reply advise (co'l actively, "Notice") provided or permitted by or this Royalty Aqraement to be 1!16da or accepted by either party mu•t ba in writing. Notice may, unlaa1 oth•rwi11a provided harain, be qiven or served by deposit.l.nq the Sllllle in th• Un.it.ad State• mail, poatage paid, registered or certified, and addr••••d to the party to be notified, with return receipt requeated1 by delivering th• oOJQa to such party, or. an agent of such party1 or by sending a po•t•pAid telagrOlll, when appropriate, addra111ed to the party to ba notified. Notice deposited in the mail in the manner hereinabove de•eribed shall be effective upon such deposit. Notice qivan in .uiy other manneJ:" shall b• effective only if and when received by the party to ba notified between the hours of 8100 A.M. and 4r00 P.M. of any busines1 d4y lofith delivery made after such hours ~o be deemed received the following business day . For the purposes of notice, the addresses of the parties shall, until changed as hereinafter provided, be as followes Owners: Harrison I nteres ts, Ltd. Te~aa Co111111erca Bank Building 707 Travis, Suite 1900 Houston, Texas 77002•3299 Attention1 Ed l

ll Producer: For Notices as to all Marketing Elections: Meridian Oil Production Inc. 2919 Allen Parkway Houston, Texae 77019' Attention: Director, Gae Supply and Transportation and Exchange For All Other Noticeai Meridian Oil Production Inc. 2919 Allen Parkway Houston, Texas 77019 Attention1 Vice President, Land partiea hereto shall have the right from tima to Th~ t111141 to their radpactive addreaae• 1 and each shall chan~• hav• r.1.qht to spacJ.fy 1u1 its address any other addre•• the within the United State• ot America by at leaat f iva (S) day• written notice to the otn•r party. (d) This Royalty Aqreement, together with the Deed• and Aaaiqrunents, contain the entire aqreement ot the parties hereto, with reqard to the Nonpa~icipatinq Royalties and the override• Ln th• Subject Interests and there are no other agreements, oral or written, other than the Deeds and the AsUqnments. This Royalty Agi-ee111ent can ba 4111ended only by writt~n agreement signed by the parties hereto, and by reference made a part hereof. (e) If any ter~, provision, or c ovenant relating to Owners' royalty or reatrict1ona imposed hereby is held by a court of competent jurisdiction to ba invalid, void, or unenforceable, the reservation of royalty interests contained in the conveyaneeis ot even d.a te herewith and the other tarJQa, provisions and covenant.a of this Royalty Aqreemant shall not be affected thereby and th• remainder of th11 terms, proviaiona, covenants and restriction• herein contained shall remain in full force and affect and in no way shall be affected, llnpa.l.red, or invalidated. (t) For a period of twelve months after the Effective Ti~e, both parties agree to use qood faith efforts to keep the material ta.r:ins and provision• of this Royalty Agreement confidential and not to disclose same to a third party, _. e.xcept as may be required or compelled by Govarmnantal Regul.ations or by order of a court of co11patent jur.l.sdiot.l.on, provided that th• parties shall not be required to keep confident.I.al information that already ls public knowledge or chat any porson by reasonable means could discover in the public domain. Th• terms of this paro9raph 9( f) shall no.r. const1tute a condition precedent and the breach of the terms of this paragraph 9(f) shall not result in the right to alter, terminate or walve the terms of this Royal ty Agree ment. rN WITNESS WliER.EOF 1 this Royalty Agre·e ment haa been duly executed in multiple counterparts (each of which ls to be deemed an oriq ina~ for all purposes) by the parties hereto on the date appearing oppo:s·it;a each pllrt:y • s s lgm1.tu:re. :

~ ~ f ...: ., . '· .·, . .

12 Dated this 22nd day of May, 1990 1 but effective for all purpoaea aa of 8100 a.m., Central oayli9ht Savings Time, on May 22, 1990, which is the "Effective Time."

Aa ;~~4~7lb IL\RRISON INTERESTS, LTD,

By1 Dan J, ~rrison !II ~ Pax_s..nai:

.,,~"'" ,,,.~, " '<"1 . rues r. Kar J.son Gencu:al Partner

OtL PRODUCTION INC,

1328S

13 ANNEXJ 10 Roya!tV Agreement fan.J J}EscrumoN OF LANQ Di:atn Ranch:

The following land located in Edwards County, Texas: Abstract Certificate Survey Original liWlllw .lillmbu ~ .Q.cau1" 1219 833 15 HE&. wr Ry Co. 2115 833 16 HE&. wr Ry Co. 1220 834 17 HE.ft WfRyCo. 3549 834 18 HE&wrRyCo. 3550 622 204 CCSD & RGN'G Ry Co. 777 623 205 CCSD &: RGNO Ry Co. LESS AND EXCEPT 13.53 ac:res out of Swvey IS; 11.89 acre.s out of Survey 16 and S.96 acres out of Survey 18 previously conveyed for highway purposea by deeds of record in Volume ''N", Pago 480. aad Volume "N", Page ~. Deed Records oC Edward& County, Teu.s. Being the same land described ln that ccnain deed from Edna Wheat Beam. a.s grantor, 10 0. J. Harrison, as grantee, dated December 31, 194S, of record in Volume 3S, Page 437, Deed Records of Edwards County, Texas. Ilaod Ba.oi:b: The following land located in Edwards and Sutton Counties, Texas: Abst. SuIV. Cert. Original lilL lio-- &._ .lll.W Graotce .Qlwuy 19 I 1369 C·ll Pc~Brown Sutton & Edwards i2 2 68 C·ll J. s. Clift Sutton /Ji. Edwards 528 3 908 C·ll Jno. V. Sloan Sulton 541 4 177 C·Ll Josephine TiDlDlon.s Sutton 507 s 166 C·ll ThomasOtls Sutton 818 l 568 CCSD & RGNO Ry Co. Sutton & Edwards 3026 2 568 C·ll CCSD & RONG Ry Co. Sutton & Edwards 1 7 13U W.A.Atldns Sutton & Edwards 490 6 562 C·ll R. MattbC\W Sutton 26 139 590 CCSD & RONG Ry Co. Sutton 27 217 629 CCSD & RONG Ry Co. Sutton 1128 8 534 C·ll Rhoda Pruitt Sutton & Edwards 1645 9 1567 C·ll Mn. E. J. ~son Sutton 1129 228 634 CCSD & R . NG Ry Co. Sutton 1130 138 589 CCSD ck RONG Ry Co. Sutton 1712 218 629 CCSD ck RONG Ry CO. Sutton & Edwards Being tbe same land desc:ribed in that certain deed from Mr$. Edith Bond ct al, as ~rantor~ to D. J. Harrieon dated Novomber 30, 194\,of record In Volume 41, Page 399 oft e Dee Records of Sutton County, Tc!tas. and in . olume 35, Pase 150 of the Deed Records of Edwards County, Teitas. A1u1elt Ranch: The following land, consisting of three blocks located in Edwards and Sutton Counties, Texas: EIBSI BLOCK Abstract Survey Certificate Original liwnW NwnW 1illm.lw .Qw1lu 846 3 4/783 GC &. SF Ry Co. 847 s 4/784 OC&SFRyCo. 852 13 4/788 GC&SFRbCo. 1596 111 516 CCSD &t. R NG Ry Co. 779 211 626 CCSD & RONG Ry Co. ·-· Abstract Suzvey Certificate Original. ~ ~ 1:iwnl2Gc ~ 780 213 627 CCSD & RGNG Ry Co. 70.S pan s 2064 Mrs. R. G. A.le.xaOOcr 29.30 210 625 CCSO & RGNO Ry Co. 3067 220 630 CCSD &. RONG Ry Co. 2601 212 626 CCSD & RONG Ry Co. 1903 4 4/783 GC &. SF Ry Co. 2039 12 4/787 GC&SFRyCo. 2038 14 4/788 GC&SFROCo. 2040 110 S1S CCSD &; R NG Ry Co. All of said surveys being i.n Edwards County, Texas. The R. G. Alexander Survey No. s described above is being limited 10 the trut covered by deed from Frank Cloudt. Sr.. 10 A~ Moos dated Dc~cmber 29, 1917, o( record In Voh.une 19, Page 633, Dc¢d Record.\ of a.rds County, Teras. Sl!OOW2 ULQCK Abstract Survey Certificate Bloelc Original ~ Hl&mtict Nwntw Nwnhu .o.taD1u 1316 92 566 CCSD & RONO Ry Co. 37 . 93 561 CCSD & RONG Ry Co• 1036 82 561 CCSD & RGNO Ry Co. .. 62 103 572 CCSD & RGNO Ry Co. 1317 104 572 CCSD A RONO Ry Co. 38 Nl/2 83 562 CCSD & RONG Ry Co. 697 83 0/632 14 TWNORyCo. 1038 106 0/643 14 TWNGRyCo. 709 107 0/644 14 TWNGJ(Co. 1037 12 180 c HE& Ry Co. 386 13 181 c HE & WT Ry Co. All of suci. surveys being In Sutton County, Te:1as. nnRJl J;U.OCK. Abst. Swv. Cert. Original Na- .tUL... lil>- 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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