No. 14-0302

IN THE SUPREME COURT OF TEXAS

CHESAPEAKE EXPLORATION, L.L.C.

AND CHESAPEAKE OPERATING, INC., Petitioners

vs.

MARTHA ROWAN HYDER, INDIVIDUALLY, AND AS INDEPENDENT

EXECUTRIX AND TRUSTEE UNDER THE WILL OF ELTON M. HYDER, JR., DECEASED, AND AS TRUSTEE UNDER THE ELTON M. HYDER JR. RESIDUARY TRUST, AND AS TRUSTEE OF THE ELTON M. HYDER JR.

MARITAL TRUST, ET AL., Respondents.

On Petition for Review from the Fourth Court of Appeals,

San Antonio, Texas, Court of Appeals No. 04-12-00769-CV

BRIEF OF AMICI CURIAE BP AMERICA PRODUCTION COMPANY, DEVON ENERGY PRODUCTION COMPANY, L.P., EOG RESOURCES,

INC., EXCO RESOURCES, INC., SHELL WESTERN E&P, INC., TRINITY RIVER ENERGY, LLC, UNIT CORPORATION, AND XTO ENERGY INC.,

IN SUPPORT OF MOTION FOR REHEARING

Steven A. Smith, Senior Counsel State Bar No. 18685800 steven-a.smith@bp.com BP AMERICA PRODUCTION COMPANY 737 North Eldridge Parkway, 3EP-9.161 Houston, Texas 77079 Phone: (281) 366-0446 Facsimile: (281) 366-0042 Counsel for Amicus Curiae BP America Production Company

Jeremy Webb, Counsel State Bar No. 24037684 Jeremy.webb@dvn.com Devon Energy Production Company, L.P. 333 West Sheridan Avenue Oklahoma City, Oklahoma 73102-5015 Phone: (405) 552-4767 Facsimile: (405) 234-2388 Counsel for Amicus Curiae Devon Energy Production Company, L.P.

FILED14-03028/5/2015 4:29:19 PMtex-6373521SUPREME COURT OF TEXASBLAKE A. HAWTHORNE, CLERK

ii

C. Robert Vote Assistant General Counsel State Bar No. 20620850 Robert_vote@eogresources.com EOG RESOURCES, INC. 1111 Bagby, Sky Lobby 2 Houston, Texas 77002 Phone: (713) 651-7000 Facsimile: (713) 651-6995 Counsel for Amicus Curiae EOG Resources, Inc.

William L. Boeing General Counsel State Bar No. 02550500 wboeing@EXCOResources.com EXCO Resources, Inc. 12377 Merit Drive Dallas, Texas 75251 Phone: (214) 368-2084 Facsimile: (214) 368-2087 Counsel for Amicus Curiae EXCO Resources, Inc.

Tim Gehl Senior Counsel State Bar No. 07791760 Tim.gehl@shell.com SHELL WESTERN E&P, INC. P.O. Box 2463 Houston, Texas 77252-2463 Phone: (713) 241-2333 Facsimile: (713) 230-3909 Counsel for Amicus Curiae Shell Western E&P, Inc.

Aaron Thesman General Counsel State Bar No. 24008146 athesman@trinityriverenergy.com TRINITY RIVER ENERGY, LLC 777 Main Street, Suite 3600 Fort Worth, Texas 76102 Phone: (817) 872-7810 Facsimile: (817) 872-7898 Counsel for Amicus Curiae Trinity River Energy, LLC

Christopher A. Brown State Bar No. 24040583 cabrown@winstead.com Winstead PC 500 Winstead Building 2728 N. Harwood Street Dallas, Texas 75201 Phone: (214) 745-5400 Facsimile: (214) 745-5390 Counsel for Amicus Curiae Unit Corporation

John Pollio, Jr. General Counsel State Bar No. 20585600 John_pollio@xtoenergy.com XTO ENERGY INC. 810 Houston St. Fort Worth, Texas 76102 Phone: (817) 885-2800 Facsimile: (817) 885-2278 Counsel for Amicus Curiae XTO Energy Inc.

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TABLE OF CONTENTS

Contents Page

TABLE OF CONTENTS ......................................................................................... iii

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

TEX. R. APP. P. 11 STATEMENT .......................................................................... vi

BRIEF OF AMICI IN SUPPORT OF REHEARING ............................................... 1

I. The Actual Price Received by Lessee. ............................................................ 2

a. The Realities of Natural Gas Marketing. .............................................. 4

b. In a Wellhead Sale, the Court’s Statements Concerning Proceeds Might be Interpreted As a Significant Departure from Texas Law. .................................................................................... 7

c. The Court’s Statements Regarding a Proceeds Lease Are Even Contrary to the Onerous Marketable Condition Rule...................................................................................................... 13

II. The Court’s Statements Concerning Proceeds, If Unchanged, May Cause Substantial Confusion in the Industry and To Lower Courts. ............................................................................................................ 14

III. Production Taxes Are Not Post-production Costs. ....................................... 15

IV. Conclusion. .................................................................................................... 19

iv

INDEX OF AUTHORITIES

CASES

Bowden v. Phillips Petroleum Co., 247 S.W.3d 690 (Tex. 2008) ................................................................................ 7

Exxon Corp. v. Middleton, 613 S.W.2d 240 (Tex. 1981) ................................................................................ 9

Fawcett v. OPIK, No. 107,422, 2015 Kan. Lexis 376 (Kan. July 6, 2015) ................................................. 4, 13, 14

Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994) (en banc) .................................................................... 4

Heritage Res. Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996) ............................................................ 11, 13, 18, 20

Holbein v. Austral Oil Co., 609 F.2d 206 (5th Cir. 1980) ................................................................................ 9

Judice v. Mewbourne Oil Co., 939 S.W.2d 133 (Tex. 1996) ................................................................................ 4

Knight v. Int’l Harvester Credit Corp., 627 S.W.2d 382 (Tex. 1982) .............................................................................. 18

Martin v. Glass, 571 F. Supp. 1406 (N.D. Tex. 1983), aff’d, 736 F.2d 1524 (5th Cir. 1984) ............................................................. 18, 19

Mittelstaedt v. Santa Fe Minerals, Inc., 954 P.2d 1203 (Okla. 1998) .................................................................................. 4

Occidental Permian Ltd. v. Helen Jones Found., 333 S.W.3d 392 (Tex. App.—Amarillo 2011, pet. denied) ................................. 9

Reed v. Hackworth, 287 S.W.2d 912, 913-14 (Ky. 1956) .................................................................. 11

Scott v. Steinberger, 213 P. 646,647 (Kan. 1923) ................................................................................ 11

v

Tana Oil & Gas Corp. v. Cernosek, 188 S.W.3d 354 (Tex. App.—Austin 2006, pet. denied) ............................. 4, 8, 9

Transamerican Natural Gas Corp. v. Finkelstein, 933 S.W.2d 591 (Tex. App.—San Antonio 1996, no writ) .................................. 9

Union Pac. Res. Group v. Hankins, 111 S.W.3d 69 (Tex. 2003)............................................................................... 7, 9

Yzaguirre v. KCS Res., Inc., 53 S.W.3d 368 (Tex. 2001)............................................................................. 7, 12

Zapata v. Ford Motor Co., 615 S.W.2d 198 (Tex. 1981) .............................................................................. 18

STATUTES

Tex. Tax Code § 201.205 (2015) ............................................................................. 16

OTHER AUTHORITIES

John W. Broomes, Waste Not, Want Not: The Marketable Product Rule Violates Public Policy Against Waste of Natural Gas Resources, 63 Kan. L. Rev. 149 (2014), 52 Rocky Mt. Min. L. Fdn. J. 157 (2015) ........................................................... 11

Joseph T. Sneed, Value of Lessor’s Share of Production Where Gas Only Is Produced, 25 Tex. L. Rev. 641 (1947) ................................................................................. 11

Scott Lansdown, The Implied Marketing Covenant in Oil and Gas Leases: The Producer’s Perspective, 31 St. Mary’s L. J. 297 (2000) ............................................................................ 11

Scott Lansdown, The Marketable Condition Rule, 44 S. Tex. L. Rev. 667 (2003) ............................................................................ 11

vi

TEX. R. APP. P. 11 STATEMENT

This brief is filed by and on behalf of the following amici, each of which

owns and operates oil and/or gas wells in the State of Texas and pays royalties

pursuant to leases requiring royalties paid on the basis of proceeds received, like

the lease at issue in this case:

BP America Production Company

Devon Energy Production Company, L.P.

EOG Resources, Inc.

EXCO Resources, Inc.

Shell Western E&P, Inc.

Trinity River Energy, LLC

Unit Corporation

XTO Energy Inc.

No fees have been or will be paid for preparation of this brief.

1

BRIEF OF AMICI IN SUPPORT OF REHEARING

The Court’s opinion may have altered the course of oil and gas

jurisprudence in Texas and changed the industry’s understanding of the meaning of

a “proceeds” lease. The opinion also creates confusion about gas production taxes,

which royalty owners are statutorily required to pay. The Amici ask the Court to

clarify its statements concerning a producer’s obligations under a proceeds royalty

clause and regarding production taxes so that they, other oil and gas producers,

royalty owners, and the courts can determine whether or not there has been lease

compliance given the manner in which natural gas is marketed.

The Court’s opinion discusses, in what appears to be dicta, the meaning of

the phrase “actual price received by the lessee” in an oil and gas lease. The Court

states that such a clause is a “proceeds” royalty provision. Proceeds royalty

clauses, according to the Court, do not allow for the deduction of post-production

costs from royalty payments. The Court then, at a minimum, implied that when

such costs are a part of a formula used to determine the purchase price to be paid to

the lessee by the buyer, those costs are not to be considered in determining the

amount of royalties owed to the lessor. In other words, the Court’s dicta could

potentially be interpreted that royalties in a “proceeds” lease are to be paid not on

the price actually received by the lessee but, rather, on the price received by the

lessee’s purchaser if the lessee’s purchaser resells the gas.

2

In making these statements, the Court did not find that the producer

breached its implied covenant to reasonably market. Neither did the Court rule

that the transaction between the producer and its buyer (an affiliated company) was

a sham. Rather, the Court relied on the terms of the oil and gas lease.

When applied to the manner and means of marketing natural gas and the

prices producers actually receive from their respective gas buyers, the Court’s

dicta, if that is what it was, has created confusion in the industry. The Court’s

statements may be interpreted to require, for the first time, a producer that acted as

reasonably prudent operator to pay royalties under a proceeds lease on money the

producer never received. Texas oil and gas law has never required a lessee with a

proceeds lease to do so. While these Amici don’t think the Court intended this

result, the Court’s statements might be interpreted as such and are likely to

generate similar confusion in lower courts around the state. The Amici,

consequently, request that the Court reconsider its statements in light of the matters

set forth below.

I. The Actual Price Received by Lessee.

The lynchpin to the Court’s statements is the determination of what was the

“actual price received by lessee” from the sale of the natural gas. It is undisputed

that much of the gas was sold at the wellhead.1 It is undisputed, and the Court

1 Findings of Fact and Conclusion of Law Nos. 13 and 15.

3

recognized, that the buyer paid the seller a wellhead price based on a formula. The

formula was the buyer’s weighted average sales price less the buyer’s costs for

gathering and transporting the gas plus a 3% marketing fee.2 In other words, the

price paid, i.e., the proceeds, to the lessee was 97% of the buyer’s weighted

average resale price adjusted for the buyer’s costs for gathering and transporting

the gas.

The Court stated, however, that the “actual price received by lessee” was not

the wellhead price paid by the buyer. Rather, the actual price received, according

to the Court, was 100% of the buyer’s weighted average sales price before the

buyer’s marketing fee and its costs to move the gas from the wellhead to the

buyer’s points of sale. While this conclusion could be tied to and limited by the

Court’s determination that the producer did not dispute that the price it actually

received was the price its affiliate received, the majority did not make this clear

and, instead broadly stated that “[t]he gas royalty does not bear postproduction

costs . . . because the amount is based on the price actually received by the lessee,

not the market value at the well.” This conclusion mistakenly conflates the “price

actually received by the lessee” with the price actually received by the buyer in a

manner that suggests a lessee must pay royalties on its buyer’s proceeds, not its

2 Opinion at 3-4, fn. 7.

4

own.3 This portion of the opinion might be interpreted as turning the legal

concepts of natural gas marketing and pricing on their head, is directly contrary to

the industry’s understanding of the actual price received by a lessee, and results in

royalty owners receiving far more than the benefit of their bargain.

Besides the economic effect, these statements could be interpreted as

reflecting a dramatic shift in Texas oil and gas jurisprudence. They would make

Texas the first state to hold that a court should ignore the plain meaning of the

royalty clause and grant a royalty owner in a single well, or on a small quantity of

gas, a royalty based on sales of large volumes of gas hundreds of miles away from

the area of production at absolutely no cost. Not even the states that recognize the

marketable condition rule, i.e., no post-production costs can be charged to royalty

until gas is in a marketable condition, have held that a “proceeds” lease means

100% deduction free.4

a. The Realities of Natural Gas Marketing.

There is nothing unusual about the pricing terms between COI and its

affiliate CEMI. In fact, these pricing terms are consistent with the industry 3 See, e.g., Tana Oil & Gas Corp. v. Cernosek, 188 S.W.3d 354, 360 (Tex. App.—Austin 2006, pet. denied) (“The Class erred by equating the sale of raw gas at the well to the separate and distinct third-party sales of the residue gas and extracted liquids on the open market. Tana did not sell the residue gas or the liquids; Tana sold raw gas at the well, before value was added by preparing the gas for market.”) (citing Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 137 (Tex. 1996)). 4 Fawcett v. OPIK, No. 107,422, 2015 Kan. Lexis 316 (Kan. July 6, 2015); Mittelstaedt v. Santa Fe Minerals, Inc., 954 P.2d 1203 (Okla. 1998); Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994) (en banc).

5

standard for a sale of natural gas at the wellhead and these same types of contracts

are routinely entered into between both affiliated and unaffiliated companies.

The majority of natural gas produced in Texas is sold by the producer at the

wellhead. Gas buyers spend millions, and in some instances billions, of dollars

constructing gathering lines to the individual wellheads in a field, as well as

dehydration and treating facilities and processing plants. In other instances,

gathering companies provide these services to buyers for a fee. Still further

downstream, large pipeline companies (also for a fee) provide transmission

services to buyers to move the gas from the field to large distribution centers

(“LDCs”) such as the Houston Ship Channel, Waha (in far west Texas), Carthage,

Texas, and locations beyond Texas’ borders. The gas is then resold by the buyers

in these LDCs to other buyers, who resell the gas, or to industrial consumers.

The value of gas produced from an individual lease or wellhead is less, and

in many instances substantially less, than the value of that same gas as part of a

much larger volume sold at the LDCs. It is a simple economic fact that natural gas

becomes more valuable as it moves from a wellhead to the LDCs because

transportation costs are already incurred as the gas moves downstream and the gas

is aggregated into the larger volumes sought by downstream buyers and the

ultimate consumers of the gas. For example, 500 mcf of gas sold separately is less

6

valuable than that same 500 mcf sold as a part of packages equaling 500,000 mcf

at the LDCs.

When a producer enters into a wellhead sales agreement, it has a couple of

basic options. It can enter into a fixed price contract or it can sell its gas for a price

that tries to capture some of the downstream value found at the LDCs. Producers

have been heavily criticized in the past for entering into fixed price contracts

because such contracts may prohibit a producer from benefiting from surging

markets both in the field and at the LDCs. The industry norm today is for a

producer to enter into a contract that gives it a portion of the enhanced prices

obtainable only at the LDCs. These can take the form of a percentage of the

buyer’s proceeds, a percentage of an index price established at the LDCs, or 100%

of the buyer’s weighted average sales price minus a marketing fee. Under any

pricing option, however, the buyer is not going to pay the producer a price for the

gas that does not allow the buyer to recover its costs and obtain a measure of profit

for its delivery and other enhancement efforts. The price paid by the buyer will

always include a formula that adjusts the prices received at the LDCs so the buyer

can make a profit and recover the cost and associated risk for moving, treating,

processing and transporting the gas it buys to the place where it sells the gas. For

example, if the buyer’s sales price at an LDC is $4.00 and the buyer’s costs are

7

$1.50, the actual price paid to the producer/lessee will be less than $2.50 once the

buyer’s costs and profit are taken into consideration.

In a wellhead gas sales agreement, the actual price received by the lessee,

i.e., the proceeds of sale, is the price the lessee receives from the buyer at the point

of sale – the wellhead. That is the gross price paid to the lessee that produces the

gas. Based on the example above, the proceeds would be less than $2.50. The

proceeds are not $4.00 because that was not the price paid to the producer by its

buyer. Thus, the royalty obligation under a proceeds lease is to pay royalties on

less than $2.50, not $4.00. The buyer’s costs are not deductions made by the

producer for one simple reason – the producer didn’t make any such deductions,

because it didn’t gather, treat, process or transport the gas beyond its point of sale,

i.e., the wellhead.

b. In a Wellhead Sale, the Court’s Statements Concerning Proceeds Might be Interpreted As a Significant Departure from Texas Law.

Prior to the Court’s dicta here, it was clear that proceeds—or “amount

realized”—leases required royalties to be paid only on the amounts actually

received by the lessee in an actual sale of gas.5 The price negotiated by the lessee

5 See Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008); Union Pac. Res. Group v. Hankins, 111 S.W.3d 69, 72 (Tex. 2003); Yzaguirre v. KCS Res., Inc., 53 S.W.3d 368, 372-73 (Tex. 2001).

8

for the sale—wherever it occurred—was the price on which proceeds was based.6

In none of those cases—in particular the “proceeds at the well” cases—did the

court hold that royalty was owed on a downstream price based on an inherent

prohibition of post-production deductions.

By implication, if not by simple logic and common sense, “proceeds” as a

basis for royalty in a lease, without further specification as to location, are the

proceeds received (i.e., amount realized) by the lessee wherever the lessee sells the

gas. This is true without regard to additional costs incurred by a third party or

marketing affiliate beyond that sales point pursuant to an independent gas sales

contract. The gas here was sold at the well. The proceeds of the sale are to be

determined by the price received at that location.

The Court runs afoul of prior authority and the commonly-accepted meaning

of proceeds leases by implying for the first time that such leases categorically

prohibit post-production deductions without specifying from what such deductions

are prohibited. This would mark the first instance in which this Court—or any

Texas court—has indicated, counter to established law, that “proceeds” means

without netting back from the buyer’s sales price at an LDC, when the wellhead

price paid to the lessee is based on the buyer’s ultimate sales minus the buyer’s

6 See, e.g., Tana Oil & Gas Corp., 188 S.W.3d at 360 (holding that a sale based on percentage of a downstream resale price for processed gas and liquids was the negotiated value of the raw gas at the point of sale—in that case at the well).

9

costs from the lessee’s point of sale to the buyer’s ultimate point of sale.7 The

footnoted cases follow the logical premise that the proceeds upon which royalties

under a lease are to be paid must be the proceeds received by a party to that lease,

not some other party with no relationship to the royalty owner. Here, the parties

intended the proceeds to be what the lessee received from its sale. It is illogical to

arbitrarily say that proceeds are amounts received by a party that has no

relationship with the royalty owner because only the lessee is a party, not the

lessee’s buyer.

As further explained in Tana Oil & Gas Corp.,8 the negotiated price in the

sales contract that entitles the lessee to proceeds is the amount realized by the

lessee. In Tana, the court analyzed an “amount realized at the well” royalty

provision and held that where the price paid for raw gas at the well was a

percentage of a downstream sales price (84% of proceeds of 100% of wellhead

7 Hankins, 111 S.W.3d at 75; Exxon Corp. v. Middleton, 613 S.W.2d 240, 245 (Tex. 1981) (cited by Transamerican Natural Gas Corp. v. Finkelstein, 933 S.W.2d 591, 598 (Tex. App.—San Antonio 1996, no writ) (noting that a lessee’s royalty obligations are determined from lease agreements that are wholly independent of gas purchase contracts); Occidental Permian Ltd. v. Helen Jones Found., 333 S.W.3d 392, 398-99 (Tex. App.—Amarillo 2011, pet. denied) (“Evidence of proceeds received by OEMI, an affiliated but different company, from sales of NGLs and residue gas at locations far removed from the wellhead is not evidence of the amount realized by OPL [lessee] from a sale of raw gas at the well.”); see also Holbein v. Austral Oil Co., 609 F.2d 206 (5th Cir. 1980) (holding that “amount realized” royalty provision requires payment of royalties “only on the amount realized from [the lessee’s] sales” and that the gas purchase contract was irrelevant for purposes of determining whether deductions for dehydration costs were appropriate under an “amount realized” lease because the lessors were not parties to the gas purchase contract). 8 188 S.W.3d at 360-61.

10

volumes), the lessors were not entitled to a royalty on the 16% because Tana never

sold the residue and natural gas liquids and did not receive the proceeds from those

sales. Instead, Tana’s “proceeds” were the negotiated price of 84% of the

downstream sales price.

Like Tana, COI never sold the production allocable to the plaintiffs’ wells to

the third parties in the downstream sales and never actually received the proceeds

that CEMI received. CEMI paid the lessee CEMI’s downstream price minus

CEMI’s costs and marketing fee. That was the actual price received by the lessee.

The Court, however, completely changed the price that is used in determining

royalty payments. Rather than being the price received by the lessee, the opinion

could be interpreted to require the use of the price received by the buyer upon a

downstream resale of the gas. In other words, someone may take the position that

the Court has determined that compliance with a proceeds lease requires the parties

to look at the amount realized by someone other than the lessee. That position is

directly contrary to the bargain reached by the parties to a proceeds lease; indeed it

is contrary to simple logic to say that “the price received by the lessee” means

anything other than that price.

The location for royalty valuation is often spelled out in the lease. When the

point of valuation is at the well—regardless of whether the lease is a market value

11

or proceeds lease—the lessee may deduct expenses incurred following production.9

Here, the lease did not specify the location for valuing the royalty. Instead, it

simply referred to “proceeds.” Thus, the Court must determine where and when

the proceeds are measured to determine the royalty due. Since the proceeds of sale

can only be determined at the place where the gas is sold, that is the place where

royalty is determined, unless the lease specifies otherwise.10 It is undisputed that

the gas was sold at the well in this case.11 The proceeds of the sale are, therefore,

determined at the well and are determined by the sales agreement between the

lessee and its buyer.12

The reason for calculating royalties in this manner is rather obvious. The

fundamental premise for employing a proceeds-based royalty is the lessor’s

9 See, e.g., Heritage Res. Inc. v. NationsBank, 939 S.W.2d 118, 122-23 (Tex. 1996). 10 In fact, commentators have stated repeatedly that where a lease calls for royalties on proceeds without identifying the point of valuation, the royalties are valued at the well. See John W. Broomes, Waste Not, Want Not: The Marketable Product Rule Violates Public Policy Against Waste of Natural Gas Resources, 63 Kan. L. Rev. 149, 150 (2014), 52 Rocky Mt. Min. L. Fdn. J. 157, 158 (2015) (citing Reed v. Hackworth, 287 S.W.2d 912, 913-14 (Ky. 1956) (“[W]here, as here, the lease is silent concerning the place of market and the price, the royalty should be applied to the fair market value of gas at the well.”); Scott v. Steinberger, 213 P. 646,647 (Kan. 1923) (where the lease simply stated that lessor was to be paid “one-eighth of all gas produced and marketed,” with no “at the well” language or any other indication of the location at which such gas was to be valued, held that royalty was to be valued at the well, with lessee authorized to deduct transportation costs from downstream sales price)); Scott Lansdown, The Marketable Condition Rule, 44 S. Tex. L. Rev. 667, 671-72 (2003); Scott Lansdown, The Implied Marketing Covenant in Oil and Gas Leases: The Producer’s Perspective, 31 St. Mary’s L. J. 297, 325 (2000); Joseph T. Sneed, Value of Lessor’s Share of Production Where Gas Only Is Produced, 25 Tex. L. Rev. 641, 655 (1947). 11 Findings of Fact and Conclusions of Law Nos. 13 and 15. 12 See supra note 3.

12

reliance on the lessee’s interest in securing the best price obtainable for the gas,

which in turn benefits the royalty owner. The duty to reasonably market, which

applies to proceeds leases in the absence of express marketing provisions, protects

the lessor from undervalued proceeds.13 A key aspect of this bargain, however, is

that the royalty is to be based on the actual amount the lessee receives, not the

amount its buyer receives after incurring costs to sell the gas in a different market

that could be, and often is, hundreds of miles from the location where the buyer

initially purchased the gas.

Significant to this case, the Respondent did not obtain a finding of fact that

the Petitioner breached any implied covenant to market. Nor did the Respondent

obtain findings of fact that the sales agreement between COI and CEMI was a

sham.14 Further, there are no findings of fact that the COI/CEMI contract was

unfair. Thus, it is apparent that the wellhead price received by COI was that which

would be obtained by a reasonably prudent operator, consistent with the covenant

to market.

13 See Yzaguirre, 53 S.W.3d at 373-74. 14 No Texas Supreme Court case has recognized the sham transaction theory. Amici are not to be understood to mean that such a theory is valid, which they do not believe it to be. We make this point merely to demonstrate that the evidence before the Court is that the COI/CEMI contract was a valid agreement that was not attacked or set aside by the lower court.

13

c. The Court’s Statements Regarding a Proceeds Lease Are Even Contrary to the Onerous Marketable Condition Rule.

A rule, if that is what was established here, that the actual price received by

the lessee, i.e., the proceeds of the sale, is the unadjusted price received by the

lessee’s buyer, is contrary to even the marketable condition rule utilized by other

states. Generically stated, the marketable condition rule requires that the lessee

place the gas in a marketable condition cost free to the royalty owner.15 After the

gas is in a marketable condition, the lessee may deduct reasonable post-production

costs that enhance the value of the gas and result in a higher price.16 The

marketable condition rule, though, is not the law in Texas.17

Recently, the Kansas Supreme Court further defined its marketable

condition rule under facts similar to those before this Court. In Fawcett v. OPIK,18

the lessee sold the gas at the wellhead to its buyer based on the following terms:

the buyer’s sales price minus the cost to gather, treat, process and then transport

the gas to the buyer’s purchaser.19 The leases required the lessee to pay royalties

on the proceeds of the sale. The lessors argued that the buyer’s costs for gathering,

treating and processing the gas should be borne solely by the producer/leseee

15 Fawcett, 2015 Kan. LEXIS 376, *19. 16 Id. 17 Heritage Res., 939 S.W.2d at 127-29 (Justice Owen concurring). 18 2015 Kan. LEXIS 376. A copy of which is attached. 19 Id. at *19.

14

because they were costs to place the gas in a marketable condition.20 According to

the lessors, these costs should be added back into the price for the payment of

royalties under a proceeds lease.21 The Kansas Supreme Court rejected the lessors’

assertions, stating:

We hold that when a lease provides for royalties based on a share of proceeds from the sale of gas at the well, and the gas is sold at the well, the operator’s duty to bear the expense of making the gas marketable does not, as a matter of law, extend beyond that geographical point to post-sale expenses. In other words, the duty to make gas marketable is satisfied when the operator delivers the gas to the purchaser in a condition acceptable to the purchaser in a good faith transaction. See Waechter, 217 Kan. 489, Syl. ¶ 2. OPIK satisfied its duty to market the gas when the gas was sold at the wellhead. When calculating Fawcett’s royalty, the post-production, post-sale processing expenses deducted by the third-party purchasers are shared.22

Thus, even in a state that applies the onerous marketable condition rule, the court

rejected the concept of requiring that royalty be based on a reconstructed price that

was not received by the lessee and that was paid by a party with no relationship

whatsoever to the royalty owner.

II. The Court’s Statements Concerning Proceeds, If Unchanged, May Cause Substantial Confusion in the Industry and To Lower Courts.

If unchanged, the Court’s dicta may force producers with proceeds leases

and industry standard wellhead sales contracts to re-determine royalties owed to

20 Id. 21 Id. 22 Id. at *26.

15

thousands, if not several hundreds of thousands, of royalty owners in Texas.

Producers may be forced to pay royalties on amounts they never received by

adding in the buyer’s costs and profit to the price the producer actually received.

In all likelihood, audits of gas buyers’ costs on a well-by-well basis will ensue to

ensure that all costs and profits are considered. In other words, the Court’s

statements concerning “proceeds” might cause the industry as a whole to re-

evaluate how they are paying royalties and could mandate expensive audits of gas

purchasers’ records that were previously unnecessary in the conduct of day-to-day

business.

Further, lower courts will be confused by the Court’s statements in this case.

District Judges will be confronted with cases in which the lessee complied with its

implied marketing obligations and received the best price obtainable for itself and

the royalty owner. Despite that, the lower courts will have to decide whether or

not the Court’s dicta requires the producer to pay royalties under a proceeds lease

based on a price the producer never received nor could have received. Texas oil

and gas law has never previously required a lessee, who acted as a reasonably

prudent operator, to do so.

III. Production Taxes Are Not Post-production Costs.

In its analysis of the overriding royalty provision in the lease, the Court

called gas production taxes “postproduction expenses.” This is contrary to Texas

16

law and settled industry practice. The Court relied on this erroneous premise to

state, “the exception for production taxes, which are postproduction expenses, cuts

against Chesapeake’s argument [that ‘cost-free’ in the overriding royalty provision

applied only to production costs].” Ultimately, the Court acknowledged that the

production tax exception is not determinative of the “cost-free” analysis but

nevertheless included this improper and unnecessary conclusion in its opinion.

Left unchanged, the suggestion that the production taxes exception discredits

Chesapeake’s argument is significant and portends a rash of royalty litigation

based on the misconception that production taxes are post-production costs.

The parties’ use of the exception of production taxes is no evidence that they

intended “cost free” to include post-production costs. First, production taxes are

not post-production costs. They are taxes that are imposed by the State based on

production. The liability for production taxes cannot be contractually altered by

one party agreeing to assume the obligation for another. In Chapter 201 governing

gas production severance taxes, the Tax Code states:

The [gas production] tax shall be borne ratably by all interested parties, including royalty interests. Producers or purchasers of gas, or both, are authorized and required to withhold from any payment due interested parties the proportionate tax due and remit it to the comptroller.23

23 Tex. Tax Code § 201.205 (2015).

17

As a plain reading of the Tax Code shows, the State requires production

taxes to be deducted from royalty payments by the party paying the royalty. The

Hyders recognized that their tax obligation is not delegable and agreed to accept “a

perpetual, cost-free (except only its portion of production taxes) overriding

royalty” in exchange for Chesapeake’s use of their surface to drill off-lease wells.

Their recognition of this obligation, however, is not evidence that all post-

production costs were Chesapeake’s sole responsibility. In fact, this language

demonstrates that the parties acknowledged the status of Texas law that overriding

royalties do not bear production costs but the parties do bear their proportionate

share of production taxes. The sweeping conclusion that the production tax

exclusion must implicate the non-deductibility of post-production costs reverses

the general rule in Texas that each party pays their proportionate share of post-

production costs.

The language the parties chose to reiterate the law is nothing but surplusage

as a matter of law and is not uncommon at all. Many oil and gas companies,

Chesapeake being one of them, have leases in many states that have different rules

of law from Texas. Accounting and royalty payment departments, though, are not

typically divided by state. As a result, many companies and their respective lessors

will place language in a lease that is nothing more than a restatement of the law of

the state where the lease exists. They do so to avoid confusion and disputes in the

18

future created by a misunderstanding of the law for a particular state. As Texas

courts have recognized many times, restatements of law in a contract are

surplusage and of no effect.24 That is what the subject Hyder language is here,

surplusage.

Second, post-production costs are not taxes. Post-production costs are the

costs to physically transform and move the gas, if necessary, from the wellhead to

the buyer who will then move the gas to the ultimate consumer.25 Those costs are

for gathering, compressing, treating, processing and transporting the natural

gas.26 As stated above, different parties (sometimes the gas buyer, sometimes the

producer) pay these costs depending on the terms of the gas sales agreement and

where the producer (not the buyer) sells the gas. Taxes, on the other hand, are

based on the act of producing the gas. If hydrocarbons are produced and saved, a

tax is owed. To equate a production tax with a marketing cost is to call an apple an

orange, especially since production taxes must always be deducted from royalties

under Texas law.

24 See, e.g., Heritage Res., 939 S.W.2d at 121-22 (where lease merely restated Texas law that there be no deductions from the value of the lessor’s royalty, the post-production provision was surplusage as a matter of law); Knight v. Int’l Harvester Credit Corp., 627 S.W.2d 382, 386 (Tex. 1982) (holding that restatement of law of sales would not operate as a waiver but rather as notice to the parties of their obligations at law); Zapata v. Ford Motor Co., 615 S.W.2d 198, 201 (Tex. 1981) (same with regard to the law of bailment). 25 Heritage Res., 939 S.W.2d at 122 (“Post-production marketing costs include transporting the gas to the market and processing the gas to make it marketable.”); Martin v. Glass, 571 F. Supp. 1406, 1410 (N.D. Tex. 1983), aff’d, 736 F.2d 1524 (5th Cir. 1984). 26 Heritage Res., 939 S.W.2d at 122; Martin, 571 F. Supp. at 1410.

19

The Court’s reference to Heritage Resources that “. . . royalty is usually

subject to post-production costs, including taxes, . . .” to conclude that Texas

considers all “taxes” to be post-production costs misinterprets Heritage. The

Heritage Court relied upon Martin v. Glass in making the above quoted

statement. Martin did not concern taxes as a post-production cost and did not

state, even in dicta, that taxes are post-production costs.27 Rather, Martin

addressed the deductibility of a compression charge and the reasonableness of the

amount deducted.28 The Heritage Court’s statements in this regard were merely

over-inclusive and did not consider the lessor’s non-delegable statutory duty to pay

its production taxes, regardless of lease language.

Thus, the Court should clarify that production taxes are not post-production

costs. This sweeping assertion is not necessary to the Court’s ultimate conclusion

and, left unchanged, will yield confusion and misplaced reliance on lease language

implicating production taxes in the future. Further, based on the current opinion,

future litigants may argue that lessors and lessees can contract around the statutory

obligation of royalty owners to pay their share of production taxes.

IV. Conclusion.

The Court should grant the motion for rehearing filed by the Petitioner in

this case. The Court’s statements concerning proceeds leases have either changed 27 Martin, 571 F. Supp. at 1416-17. 28 Id.

20

the law in Texas to hold that “proceeds” means more than the sales price under a

gas sales agreement or have clouded the meaning of “proceeds” sufficiently that

producers and lower courts will be attempting to determine the meaning of the

Court’s ruling until such time as this Court gives further guidance. As Justice

Owens stated in her concurring opinion in the Heritage Resources case:

In construing language commonly used in oil and gas leases, we must keep in mind that there is a need for predictability and uniformity as to what the language used means. Parties entering into agreements expect that the words they have used will be given the meaning generally accorded to them.29

By clarifying, or amending, its statements concerning how proceeds in a proceeds

lease are to be determined, the parties to oil and gas leases and the courts can better

understand the Court’s holding in this case. Further, by clarifying its statements

regarding gas production taxes, the Court will avoid future confusion among

lessors and lessees in Texas concerning their rights and obligations under the

Texas Tax Code and leases referring to deduction of production taxes.

29 939 S.W.2d at 129-30.

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Respectfully submitted, /s/ Steven A. Smith Steven A. Smith Senior Counsel State Bar No. 18685800 steven-a.smith@bp.com BP America Production Company 737 North Eldridge Parkway, 3EP-9.161 Houston, Texas 77079 Phone: (281) 366-0446 Facsimile: (281) 366-0042 Counsel for Amicus Curiae BP America Production Company

/s/ Jeremy Webb Jeremy Webb Counsel State Bar No. 24037684 Jeremy.webb@dvn.com Devon Energy Production Company, L.P. 333 West Sheridan Avenue Oklahoma City, Oklahoma 73102-5015 Phone: (405) 552-4767 Facsimile: (405) 234-2388 Counsel for Amicus Curiae Devon Energy Production Company, L.P.

/s/ C. Robert Vote C. Robert Vote Assistant General Counsel State Bar No. 20620850 Robert_vote@eogresources.com EOG Resources, Inc. 1111 Bagby, Sky Lobby 2 Houston, Texas 77002 Phone: (713) 651-7000 Facsimile: (713) 651-6995 Counsel for Amicus Curiae EOG Resources, Inc.

/s/ William L. Boeing William L. Boeing General Counsel State Bar No. 02550500 wboeing@EXCOResources.com EXCO Resources, Inc. 12377 Merit Drive Dallas, Texas 75251 Phone: (214) 368-2084 Facsimile: (214) 368-2087 Counsel for Amicus Curiae EXCO Resources, Inc.

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/s/ Tim Gehl Tim Gehl Senior Counsel State Bar No. 07791760 Tim.gehl@shell.com Shell Western E&P, Inc. P.O. Box 2463 Houston, Texas 77252-2463 Phone: (713) 241-2333 Facsimile: (713) 230-3909 Counsel for Amicus Curiae Shell Western E&P, Inc.

/s/ Aaron Thesman Aaron Thesman General Counsel State Bar No. 24008146 athesman@trinityriverenergy.com Trinity River Energy, LLC 777 Main Street, Suite 3600 Fort Worth, Texas 76102 Phone: (817) 872-7810 Facsimile: (817) 872-7898 Counsel for Amicus Curiae Trinity River Energy, LLC

/s/ Christopher A. Brown Christopher A. Brown State Bar No. 24040583 cabrown@winstead.com Winstead PC 500 Winstead Building 2728 N. Harwood Street Dallas, Texas 75201 Phone: (214) 745-5400 Facsimile: (214) 745-5390 Counsel for Amicus Curiae Unit Corporation

/s/ John Pollio, Jr. John Pollio, Jr. General Counsel State Bar No. 20585600 John_pollio@xtoenergy.com XTO Energy Inc. 810 Houston St. Fort Worth, Texas 76102 Phone: (817) 885-2800 Facsimile: (817) 885-2278 Counsel for Amicus Curiae XTO Energy Inc.

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CERTIFICATE OF COMPLIANCE

In accordance with the recently amended Rule 9.4 of the Texas Rules of Appellate Procedure, the undersigned certifies that this Brief of Amici Curiae has been prepared using Microsoft Word, in 14-point Times New Roman font for the text and 12-point Times New Roman font for any footnotes. This Brief contains 5,317 words, as determined by the word count feature of the word processing program used in preparing this document, excluding those portions exempted by Tex. R. App. P. 9.4(i)(1).

/s/ Christopher A. Brown ONE OF COUNSEL

24

CERTIFICATE OF SERVICE

The undersigned certifies that on the 5th day of August, 2015, a true and correct copy of the foregoing Brief of Amici Curiae in Support of Motion for Rehearing was filed electronically with electronic service to the following and was also sent via certified mail, return receipt requested, to the following:

Bart A. Rue bart.rue@kellyhart.com Matthew D. Stayton matt.stayton@kellyhart.com Kelly Hart & Hallman LLP 201 Main Street, Suite 2500 Fort Worth, Texas 76102

Deborah G. Hankinson dhankinson@hankinsonlaw.com Stephanie Dooley Nelson snelson@hankinsonlaw.com Rebecca Adams Cavner bcavner@hankinsonlaw.com HANKINSON LLP 750 N. St. Paul Street, Suite 1800 Dallas, Texas 75201

Counsel for Petitioners David J. Drez III david.drez@wickphillips.com Jeffrey W. Hellberg, Jr. jeff.hellberg@wickphillips.com Jacob T. Fain jacob.fain@wickphillips.com Wick Phillips Gould

& Martin, LLP 100 Throckmorton, Suite 500 Fort Worth, Texas 76102 Counsel for Respondents

Michael A. Heidler mheidler@velaw.com Vinson & Elkins LLP 2801 Via Fortuna, Suite 100 Austin, Texas 78746

Marie R. Yeates myeates@velaw.com Vinson & Elkins LLP 1001 Fannin Street, Suite 2500 Houston, Texas 77002

Counsel for Amicus Curiae Texas Oil & Gas Association

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Roger D. Townsend rtownsend@adjtlaw.com Robert B. Dubose rdubose@adjtlaw.com Alexander Dubose Jefferson

& Townsend LLP 1844 Harvard Street Houston, Texas 77008

Dana Livingston dlivingston@adjtlaw.com Alexander Dubose Jefferson

& Townsend LLP 515 Congress Avenue Suite 2350 Austin, Texas 78701

Counsel for Amicus Curiae Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP

John B. McFarland jmcfarland@gdhm.com Graves, Dougherty, Hearon

& Moody, P.C. 401 Congress Avenue, Suite 2200 Austin, Texas 78701-3744

Hon. Raul A. Gonzalez rgonzalezlaw@aol.com 10511 River Plantation Dr. Austin, Texas 78747

Attorneys for Amicus Curiae Texas Land and Mineral Owners Association and National Association of Royalty Owners-Texas

Ken Slavin kslavin@kempsmith.com KEMP SMITH LLP 221 North Kansas, Suite 1700 El Paso, Texas 79901 Counsel for Amicus Curiae The General Land Office of the State of Texas

/s/ Christopher A. Brown ONE OF COUNSEL