Chesapeake v hyder amici curiae brief 8-5-15

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
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.
FILED
14-0302
8/5/2015 4:29:19 PM
tex-6373521
SUPREME COURT OF TEXAS
BLAKE A. HAWTHORNE, CLERK

ii
C. Robert Vote
Assistant General Counsel
Robert_vote@eogresources.com
EOG RESOURCES, INC.
1111 Bagby, Sky Lobby 2
Phone: (713) 651-7000
Facsimile: (713) 651-6995
Counsel for Amicus Curiae EOG
Resources, Inc.
William L. Boeing
General Counsel
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
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
Shell Western E&P, Inc.
Aaron Thesman
General Counsel
athesman@trinityriverenergy.com
TRINITY RIVER ENERGY, LLC
777 Main Street, Suite 3600
Fort Worth, Texas 76102
Phone: (817) 872-7810
Facsimile: (817) 872-7898
Trinity River Energy, LLC
Christopher A. Brown
cabrown@winstead.com
Winstead PC
500 Winstead Building
2728 N. Harwood Street
Dallas, Texas 75201
Phone: (214) 745-5400
Facsimile: (214) 745-5390
Unit Corporation
John Pollio, Jr.
General Counsel
John_pollio@xtoenergy.com
XTO ENERGY INC.
810 Houston St.
Phone: (817) 885-2800
Facsimile: (817) 885-2278
XTO Energy Inc.

iii
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:
Devon Energy Production Company, L.P.
EOG Resources, Inc.
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.

21
Respectfully submitted,
/s/ Steven A. Smith
Steven A. Smith
Senior Counsel
steven-a.smith@bp.com
737 North Eldridge Parkway,
3EP-9.161
Phone: (281) 366-0446
Facsimile: (281) 366-0042
/s/ Jeremy Webb
Jeremy Webb
Counsel
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
Robert_vote@eogresources.com
EOG Resources, Inc.
1111 Bagby, Sky Lobby 2
Phone: (713) 651-7000
Facsimile: (713) 651-6995
EOG Resources, Inc.
/s/ William L. Boeing
William L. Boeing
General Counsel
wboeing@EXCOResources.com
12377 Merit Drive
Dallas, Texas 75251
Phone: (214) 368-2084
Facsimile: (214) 368-2087
Counsel for Amicus Curiae EXCO
Resources, Inc.

22
/s/ Tim Gehl
Tim Gehl
Senior Counsel
Tim.gehl@shell.com
P.O. Box 2463
Houston, Texas 77252-2463
Phone: (713) 241-2333
Facsimile: (713) 230-3909
/s/ Aaron Thesman
Aaron Thesman
General Counsel
athesman@trinityriverenergy.com
Phone: (817) 872-7810
Facsimile: (817) 872-7898
/s/ Christopher A. Brown
Christopher A. Brown
cabrown@winstead.com
Winstead PC
500 Winstead Building
2728 N. Harwood Street
Dallas, Texas 75201
Phone: (214) 745-5400
Facsimile: (214) 745-5390
Unit Corporation
/s/ John Pollio, Jr.
John Pollio, Jr.
General Counsel
John_pollio@xtoenergy.com
XTO Energy Inc.
810 Houston St.
Phone: (817) 885-2800
Facsimile: (817) 885-2278
XTO Energy Inc.

23
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
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
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
Counsel for Amicus Curiae Texas Oil & Gas Association

25
Roger D. Townsend
rtownsend@adjtlaw.com
Robert B. Dubose
rdubose@adjtlaw.com
Alexander Dubose Jefferson
& Townsend LLP
1844 Harvard Street
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
The General Land Office of the
State of Texas
/s/ Christopher A. Brown
ONE OF COUNSEL

Chesapeake v hyder amici curiae brief 8-5-15

Recommended

Recommended

More Related Content

Similar to Chesapeake v hyder amici curiae brief 8-5-15

Similar to Chesapeake v hyder amici curiae brief 8-5-15 (20)

More from Christopher Paris, JD, RL

More from Christopher Paris, JD, RL (6)

Recently uploaded

Recently uploaded (20)

Chesapeake v hyder amici curiae brief 8-5-15