Bounty Minerals, LLC v. Chesapeake Exploration, L.L.C. et al

Filing 107

Memorandum Opinion and Order. For all the reasons set forth in this order,the Plaintiff's Motion to Strike (Doc. No. 94 ) is DENIED, and Defendants' Motion for Summary Judgment (Doc. No. 81 ) is GRANTED. Entered by Judge Pamela A. Barker on 12/23/2019. (W,RA)

IN THE UNITED STATES DISTRICT COURT
FOR THE NORTHERN DISTRICT OF OHIO

Bounty Minerals, LLC,

Case No. 5:17cv1695
Plaintiff,

-vs-

JUDGE PAMELA A. BARKER

Chesapeake Exploration, LLC,
et al.,

MEMORANDUM OPINION AND
ORDER

Defendants

Currently pending are the following motions: (1) the Motion of Defendants Chesapeake
Exploration, LLC. and Chesapeake Operating, LLC for Summary Judgment (Doc. No. 81); and (2)
Plaintiff Bounty Minerals, LLC.’s Motion to Strike Defendants’ Notice of Supplemental Authority
(Doc. No. 94.) For the following reasons, Plaintiff’s Motion to Strike (Doc. No. 94) is DENIED, and
Defendants’ Motion for Summary Judgment (Doc. No. 81) is GRANTED.
I.

Procedural History
The procedural history of this matter has been recounted in prior decisions of this Court (see

e.g., Doc. Nos. 22, 70) and will not be repeated in full herein. Rather, the Court will only set forth
that procedural background necessary to provide context for the pending Motions.
On July 11, 2017, Plaintiff Bounty Minerals, LLC (hereinafter “Plaintiff” or “Bounty
Minerals”) filed a Complaint against Defendants 1 in the Court of Common Pleas of Carroll County,

1

In its original Complaint, Bounty Minerals named three Defendants: Chesapeake Exploration, LLC; Chesapeake
Operating, LLC; and Chesapeake Energy Marketing, LLC. (Doc. No. 1-1.) As discussed infra, Bounty Minerals twice
amended its Complaint. In its Second Amended Complaint (filed February 14, 2018), Bounty Minerals named only
Chesapeake Exploration, LLC and Chesapeake Operating, LLC. (Doc. No. 36.)

Ohio, seeking to recover royalties it believes it is owed under the terms of several oil and gas leases.
(Doc. No. 1-1.) In this Complaint, Bounty Minerals asserted two breach of contract claims as well
as a claim for declaratory judgment pursuant to Ohio Rev. Code § 2721.01 et seq. (Id.) Defendants
removed the action to this Court on August 14, 2017, on the basis of diversity jurisdiction. (Doc. No.
1.)
Shortly after removal, Defendants moved to compel arbitration with respect to one of the
subject leases, and to stay this action relative to the remaining leases pending the outcome of
arbitration. (Doc. No. 7.) Bounty Minerals responded by moving to amend the Complaint to remove
from the litigation the lease that served as the basis for Defendants’ request for arbitration. (Doc. No.
16.) On December 1, 2017, this Court (through then-assigned District Judge Sara Lioi) granted
Bounty Minerals’ motion to amend, permitting it to file an Amended Complaint that omitted the lease
with the arbitration clause. (Doc. No. 22.) The Court also denied Defendants’ motion to stay. (Id.)
Bounty Minerals filed its Amended Complaint on December 6, 2017 and the Court thereafter
conducted a CMC on January 8, 2018, at which it set various case management deadlines. (Doc.
Nos. 25, 30.) Shortly thereafter, Defendants filed a Motion for Partial Dismissal, in which it sought
an Order (a) dismissing all claims against Chesapeake Operating, (b) dismissing Count II (Breach of
Contract) and Count III (Declaratory Judgment) of Plaintiff’s Amended Complaint in their entirety;
and (c) dismissing all claims against Chesapeake Energy Marketing. (Doc. No. 31.) In lieu of a
response, Bounty Minerals filed a Motion for Leave to file a Second Amended Complaint. (Doc. No.
32.) On February 14, 2018, the Court granted Bounty Minerals’ Motion to Amend, finding that the
proposed amended complaint cured the alleged deficiencies set forth in Defendants’ Partial Motion
to Dismiss. (Doc. No. 35.)
2

Bounty Minerals filed its Second Amended Complaint that same day. (Doc. No. 36.) Therein,
it asserted the following alternative claims: (1) breach of contract against all Defendants based on
Defendants’ alleged breach of the royalties provisions of the subject oil and gas leases (Count I); (2)
breach of contract claims against Defendant Chesapeake Exploration, LLC based on Defendant’s
alleged breach of the express covenant of good faith and reasonable prudent operator (Count II); and
(3) breach of contract against all Defendants based on Defendants’ alleged breach of the affiliate sales
provisions of the subject leases (Count III). (Id.)
The docket reflects the parties subsequently engaged in discovery. (Doc. Nos. 41, 42.) On
August 10, 2018, Bounty Minerals filed another Motion for Leave to Amend Complaint, in which it
sought to add several new defendants. 2 (Doc. No. 54.) Arguing the proposed new defendants would
destroy diversity jurisdiction, Bounty Minerals also sought remand to state court. (Id.) On August
20, 2018, the Court conducted a status conference with counsel and the parties. (Doc. No. 70 at p.
3.) During that conference, the parties agreed to explore the possibility of settlement. (Id.) Later
that month, the parties filed a joint motion to temporarily stay all case management deadlines so that
the parties could participate in mediation. (Doc. No. 59.) The Court granted the motion and stayed
the case. (Doc. No. 61.)
The Court lifted the stay on January 10, 2019, after mediation failed to produce a resolution.
On February 26, 2019, the Court issued an Opinion & Order denying Bounty Minerals’ Motion for
Leave to Amend and for Remand, finding that “the balance of equities compels the conclusion that

2
Specifically, Bounty Minerals sought to add CHK Utica, LLC; Total E&P USA, Inc.; and Pelican Energy, Inc., as
Defendants, on the grounds that discovery had revealed that these entities have working interests in one or more of the
subject leases.

3

Bounty Minerals should not be permitted to further amend its complaint to defeat jurisdiction.” (Doc.
No. 70 at p. 9.)
On April 12, 2019, Defendants Chesapeake Exploration, LLC and Chesapeake Operating,
LLC (hereinafter referred to collectively as the “Chesapeake Defendants”) filed a Motion for
Summary Judgment as to each of Plaintiff’s claims. (Doc. No. 81.) Bounty Minerals filed a Brief in
Opposition on May 3, 2019 (Doc. No. 83), to which the Chesapeake Defendants replied on May 17,
2019 (Doc. No. 84.)
On June 26, 2019, the case was transferred to the undersigned pursuant to General Order
2019-13. On October 30, 2019, the Chesapeake Defendants filed a “Notice of Supplemental
Authority” in support of their Motion for Summary Judgment. (Doc. No. 93.) Bounty Minerals
moved to strike the Chesapeake Defendants’ Notice on November 1, 2019. (Doc. Nos. 94, 95.) On
November 15, 2019, the Chesapeake Defendants filed a Brief in Opposition. (Doc. No. 96.)
On December 13, 2019, the Court conducted oral argument on the Chesapeake Defendants’
Motion for Summary Judgment. 3 (Doc. No. 102.)

3

Three days prior to oral argument, on December 10, 2019, the certified class of plaintiff landowners in Zehentbauer
Family Land LP, et al. v. Chespeake Exploration, Case No. 4:15cv2449 (N.D. Ohio) (Pearson, J.) filed a Motion for
Leave to file Amicus Curiae Brief in the instant action. (Doc. No. 99.) Therein, the Zehentbauer class argued that this
Court lacked jurisdiction over three of the oil and gas leases at issue herein, and the parties to the instant action had
improperly failed to join Plaintiff’s co-lessors on those leases as indispensable parties. (Id.) The Zehentbauer class also
expressed concern “about the completeness of the arguments which plaintiff Bounty Minerals has asserted before this
Court.” (Id. at p. 4.) Plaintiff filed a Motion to Strike the Motion for Leave to file Amicus Curiae Brief on December 11,
2019. (Doc. No. 100.) Defendants filed a Response to both the Motion for Leave and Motion to Strike on December 12,
2019. (Doc. No. 101.) During oral argument on December 13, 2019, the Court heard argument about (1) the issues of
subject matter jurisdiction and indispensable parties raised by the Zehentbauer class; and (2) the parties’ substantive
arguments relative to the Chesapeake Defendants’ Motion for Summary Judgment. The Court ordered both the parties
and the Zehentbauer class to submit supplemental briefing regarding the issues of subject matter jurisdiction and
indispensable parties. (Doc. No. 102.) Supplemental briefing was thereafter timely submitted on December 20, 2019.
(Doc. Nos. 103, 104, 105.) In an opinion issued separately this date, the Court rejected the Zehentbauer class’ arguments
that this Court lacked subject matter jurisdiction and/or that the parties had failed to join indispensable parties pursuant
to Fed. R. Civ. P. 19. (Doc. No. 106.)

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II.

Facts
Bounty Minerals is in the business of purchasing oil and gas rights, including lease royalty

interests, in the shale gas areas of Ohio, Pennsylvania, and West Virginia. (Doc. No. 36 at ¶ 6.) At
issue in the present dispute are six (6) oil and gas leases that Bounty Minerals acquired between 2013
and 2015. (Id. at ¶¶ 8-17.) These Leases are identified in the Second Amended Complaint as follows:
(1) the December 16, 2010 and January 7, 2011 leases between Alan L. Miller and Ohio Buckeye
Energy, LLC (hereinafter “the Miller Leases”) (Doc. No. 36-2); (2) the October 8, 2011 lease between
Christopher and Sandi Ryland and Chesapeake Exploration (hereinafter “the Ryland Lease”) (Doc.
No. 36-4); (3) the March 9, 2011 lease between Dean Cobbs and Chesapeake Exploration (hereinafter
“the Cobbs Lease”) (Doc. No. 36-6); (4) the May 3, 2013 lease between Mark and Elizabeth Ingham
and Chesapeake Exploration (hereinafter “the Ingham Lease”) (Doc. No. 36-8); and (5) the October
8, 2011 lease between Michael and Dana Ritchie and Chesapeake Exploration (hereinafter “the
Ritchie Lease”) (Doc. No. 36-10). 4 (Id.)
The above Leases contain royalty provisions with respect to both oil and gas. The gas royalty
provisions as set forth in the subject Leases are nearly identical, and provide as follows:
9.

ROYALTIES. The Lessee covenants and agrees:
***

b.
Gas Royalty. To pay to the lessor EIGHTEEN AND ONE HALF percent
(18.5%) royalty based upon the gross proceeds paid to Lessee for the gas marketed
and used off the leased premises, including casinghead gas or other gaseous substance,

4

It is undisputed that Bounty Minerals owns a partial, undivided interest in the Ryland, Ingham and Ritchie leases.
Specifically, the deeds associated with these leases show that Bounty owns a 28.3367% interest in the Ryland lease; a
40% interest in the Ingham lease; and a 50% interest in the Ritchie lease. (Doc. Nos. 36-3 at PageID# 1724; 36-7 at
PageID# 1779; 36-9 at PageID# 1811.) The record reflects that Bounty Minerals owns 100% of the Miller and Cobbs’
leases. (Doc. Nos. 36-1, 36-5.)

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and produced from each well drilled thereon, computed at the wellhead from the
sale of such gas substances so sold by Lessee in an arms-length transaction to an
unaffiliated bona fide purchaser, or if the sale is to an affiliate of Lessee, the price
upon which royalties are based shall be comparable to that which could be
obtained in an arms-length transaction (given the quantity and quality of the gas
available for sale from the leased premises and for a similar contract term) and
without any deductions or expenses. For purposes of this Lease, "gross proceeds"
means the total consideration paid for oil, gas, associated hydrocarbons, and
marketable by-products produced from the leased premises without deductions of any
kind except as provided in paragraph 44.
Ryland Lease at ¶ 9 (Doc. No. 36-4) (emphasis added). 5
The oil royalty provisions differ among the various Leases. The Ryland, Ritchie, and Ingham
Leases provide that the Lessee agrees as follows:
To pay to the Lessor EIGHTEEN AND ONE HALF percent (18.5%) 6 royalty based
upon the gross proceeds paid to Lessee from the sale of oil, including without
limitation other liquid hydrocarbons or their constituents and products thereof
recovered from the leased premises so sold by Lessee in an arms-length
transaction to an unaffiliated bona fide purchaser, or if the sale is to an affiliate
of Lessee, the price upon which royalties are based shall be comparable to that
which could be obtained in an arms-length transaction (given the quantity and
quality of said products available for sale from the leased premises and for a
similar contract term) and without any deductions or expenses. For purposes of
this Lease, "gross proceeds" means the total consideration paid for oil, gas, associated
hydrocarbons, and marketable by-products produced from the leased premises without
deductions of any kind except as provided in paragraph 44.
See Doc. Nos. 36-4, 36-8, 36-10 (emphasis added). The Miller and Cobbs Leases provide that the
Lessee agrees:

5
The above language was taken from the Ryland Lease but is identical to the Gas Royalty Provisions in the Ritchie,
Ingham, Miller and Cobbs Leases in all material respects. Specifically, the only difference between the Ryland Lease
Gas Royalty Provision and the corresponding Ingham provision is the fact that the latter contains a 20% (as opposed to
18.5%) royalty payment. (Doc. No. 36-8.) The Miller and Cobbs leases differ from the Ryland Lease in that the Miller
and Cobbs Leases allow for the deduction of “Lessor’s prorated share of any tax, severance or otherwise, imposed by any
government body.” (Doc. Nos. 36-2, 36-6.) Neither the percentage of the royalty payment or the tax deduction language
in the Miller and Cobbs Leases, however, bear any relevance to the instant dispute.
6

The Ryland and Ritchie Leases provide for an 18.5% royalty payment, while the Ingham Lease provides for a 20%
royalty payment. See Doc. Nos. 36-4, 36-8, 36-10.

6

To pay Lessor seventeen and one half percent (17.5%) royalty based upon the gross
proceeds paid to Lessee from the sale of oil recovered from the lease premises valued
at the purchase price received for oil prevailing on the date such oil is run into
transporter trucks or pipelines.
See Doc. Nos. 36-2 at PageID#s 1684, 1704; 36-6.
Also of relevance herein, each of the six leases at issue impose an obligation on the Lessee to
act “as a reasonable prudent operator exercising good faith in all of its activities with the Lessor.”
See Doc. Nos. 36-2 at PageID# 1683, 1703; 36-4 at PageID# 1731; 36-6 at PageID# 1757; 36-8 at
PageID# 1787; 36-10 at PageID# 1817.
Chesapeake Exploration, Chesapeake Operating, and Chesapeake Energy Marketing are
affiliates of one another and are all subsidiaries of Chesapeake Energy. See Deposition of Joshua
Bowles (hereinafter “Bowles Depo.”) at Tr. 21-22 (Doc. No. 76-1).

Defendant Chesapeake

Exploration was the Lessee under the Leases at issue herein, as well as the operator and producer of
the wells covered by the Leases. (Bowles Depo. at Tr. 30-33). Chesapeake Exploration installed
centralized production pads at which the oil and gas are produced from several wells in a unit and
delivered to a separator. See Expert Report of K. Terry dated February 9, 2019 (hereinafter “Terry
Expert Report”) at ¶ 24 (Doc. No. 81-5.) The oil is separated and put in a tank, and the separated gas
is measured and metered into the first receiving pipeline. (Id.)
Chesapeake Exploration sold the oil to Chesapeake Energy Marketing (“CEM”) at the oil
storage tanks located near the wellheads on the lease or unit premises. (Id. at ¶ 25.) With respect to
gas produced at the wells at issue, Chesapeake Exploration sold the gas to CEM at the production pad
based on the volumes of gas metered. (Id. at ¶ 26.) CEM then transported the oil, gas, and natural

7

gas liquids from the wellhead and entered into contracts with third-party midstream companies 7 to
perform various “post-production services,” including gathering, treating, processing, storing, and
transporting the oil, gas and natural gas liquids to downstream delivery points. See Terry Expert
Report at ¶¶ 23, 26; Bowles Depo. at Tr. 102. According to Defendants, these post-production
services “refine and enhance the value” of the oil, gas, and the natural gas liquids, thus allowing CEM
to resell them at higher prices downstream. (Doc. No. 81-2 at p 5) (citing Bowles Depo. at Tr. 235236.)
Pursuant to an Agency Agreement with Chesapeake Exploration, Defendant Chesapeake
Operating (“CO”) received payment from CEM and calculated and paid Bounty Minerals royalties
on behalf of Chesapeake Exploration. (Terry Expert Report at ¶ 27.) Along with the royalty
payments, Chesapeake Operating provided Revenue Statements to Bounty Minerals, copies of which
are attached to the Second Amended Complaint. (Doc. No. 36-12.) These Statements contain
columns for, among other things, the month of production, what substances were produced, the
volumes of substances produced, the price received for the sale of substances produced, applicable
taxes, deductions and the royalty owner’s interest in the substances that were produced and sold.
(Doc. No. 36 at ¶ 30.)
According to Bounty Minerals, the Revenue Statements it received from Chesapeake
Operating represented that there were no deductions of post-production costs from the royalty paid
to Bounty Minerals associated with the Leases at issue, “as the columns on the Revenue Statement
associated with such costs and deductions showed ‘.00.’” (Id. at ¶ 32.) Bounty Minerals claims that,

7

According to Defendants’ Expert, Kris Terry, the “[t]he midstream sector encompasses the activities that move gas and
other hydrocarbons from the wells to the downstream points,” and “includes such things as gathering, treating, processing,
storage, pipeline transportation, and fractionation.” (Terry Expert Report at ¶ 23.)

8

over time, it noticed that the sales values of the oil, gas, and natural gas liquids in the Revenue
Statements associated with the Leases at issue were “substantially less” than the sales values of
hydrocarbons on royalty stubs associated with other of Bounty’s oil and gas leases in the same vicinity
in the same timeframe. (Id. at ¶ 33.)
Thus, on May 15, 2015, Lesley Thompson of Bounty Minerals sent an email to Chesapeake
Energy’s landowner relations department for clarification.

(Doc. No. 36-13.)

Therein, Mr.

Thompson noted that, for the Ohio wells, “the gross deductions are zero and the net deductions are
zero,” and asked “does that mean that there are no deductions for drilling and operating these wells?”
(Id.) On May 19, 2015, Chesapeake Energy’s Revenue Team responded as follows:
For the Ohio wells, there are post-production costs associated with these wells,
however these are not broken out on the check stub. We are passing on 100% of the
price/post-production costs from the purchaser for the sale of the product. Any fees
incurred by our purchaser from the wellhead to the final sales point are applied to the
revenue prior to it being paid to Chesapeake for distribution.
(Id.) Chesapeake Energy also provided Bounty Minerals with a number of spreadsheets that
identified post-production costs associated with a variety of wells that paid a production royalty to
Bounty Minerals pursuant to the Leases. (Doc. No. 36-14.)
When Bounty Minerals compared the data in the spreadsheets to the Revenue Statements
associated with the Leases at issue, it claims to have found “substantial differences” between the two
documents. (Doc. No. 36 at ¶ 37.) Bounty Minerals and Chesapeake Exploration then exchanged a
series of letters regarding these alleged discrepancies. (Id. at ¶ 41.) Of note, on July 16, 2019, Ben
Harris from Chesapeake Exploration sent Mr. Thompson a letter that provided, in relevant, part as
follows:
By way of background, Chesapeake sells the oil and gas produced from the Lease to
Chesapeake Energy Marketing, L.L.C. ("CEMLLC"), which is an affiliated marketing
9

company that takes title to, and possession of, the oil and gas at or near the well.
CEMLLC pays Chesapeake 97% of the proceeds it receives from the sale of the gas
and natural-gas liquids, and 99% of the proceeds it receives from the sale of oil, less
any postproduction costs incurred between the wellhead and downstream points
of sale. CEMLLC retains a marketing fee of 3% and 1% for gas and oil respectively;
neither marketing fee is passed on to the lessor. The price Chesapeake receives from
CEMLLC for the sale of oil and gas, plus an amount equal to the 3% or 1% marketing
fee referenced above, is the value shown in the "Price" column of the royalty
statement.
***
***** [With respect to gas], [t]he sale of gas to an affiliated purchaser is expressly
contemplated by the terms of the Lease, and the Lease provides that your royalties are
to be computed at the wellhead. Since Chesapeake bears 100% of the CEMLLC
marketing fee and since the price Chesapeake receives from CEMLLC is based on
sales to unaffiliated third party purchasers and CEMLLC's actual downstream costs,
we believe the price received in the sale to CEMLLC is comparable to or better than
that which could be obtained from an unaffiliated third party purchaser at the wellhead.
For these reasons, Chesapeake believes royalties are being paid properly under the
Lease.
(Doc. No. 36-15.)
As further explained by the Chesapeake Defendants during discovery, Bounty Minerals’
royalty payments are based on the wellhead value of the gas, as calculated via the “netback method.”
(Doc. No. 81-4 at p. 9.) To determine the wellhead value using this method, CEM calculated a
weighted average sales price by adding all revenues from downstream sales transactions and dividing
by the total volume sold. (Bowles Depo. at Tr. 145-146, 206-207.) CEM then subtracted the postproduction costs it incurred from the weighted-average sales price it obtained from third-party
purchasers to calculate the wellhead value of the gas. (Id.)
It is Defendants’ position that calculation of the wellhead value via the “netback method” is
in compliance with the express terms of the royalty provisions in the subject Leases. Bounty Minerals
disagrees, arguing that Defendants’ position is based on the incorrect presumption that the Leases
10

compel that the royalty payment be calculated “at the wellhead.” To the contrary, Bounty Minerals
asserts that the Leases’ reference to the “wellhead” as the point of royalty calculations is not
applicable to affiliate sales, such as those between Chesapeake Exploration and CEM. Rather,
Bounty Minerals maintains that the “affiliate sales” clause of the Leases dictates that royalty
payments be “comparable to that which could be obtained in an arms length transaction (given the
quantity and quality of the gas available for sale from the leased premises and for a similar contract
term) and without any deductions or expenses.” (Doc. No. 83 at p. 13.) Under this method, Bounty
Minerals argues that royalty calculations should be based on downstream (rather than wellhead) sales
values. (Id. at pp. 15-16.)
III.

Standard of Review
Summary judgment is proper “if the movant shows that there is no genuine dispute as to any

material fact and the movant is entitled to judgment as a matter of law.” Fed. R. Civ. P. 56(a). “A
dispute is ‘genuine’ only if based on evidence upon which a reasonable jury could return a verdict in
favor of the non-moving party.” Henderson v. Walled Lake Consol. Sch., 469 F.3d 479, 487 (6th Cir.
2006). “Thus, ‘the mere existence of a scintilla of evidence in support of the plaintiff’s position will
be insufficient; there must be evidence on which the jury could reasonably find for the plaintiff.’”
Cox v. Kentucky Dep’t of Transp., 53 F.3d 146, 150 (6th Cir. 1995) (quoting Anderson v. Liberty
Lobby, Inc., 477 U.S. 242, 252 (1986)). A fact is “material” only “if its resolution might affect the
outcome of the suit under the governing substantive law.” Henderson, 469 F.3d at 487.
At the summary judgment stage, “[a] court should view the facts and draw all reasonable
inferences in favor of the non-moving party.” Pittman v. Experian Info. Solutions, Inc., 901 F.3d
619, 628 (6th Cir. 2018). In addition, “the moving party bears the initial burden of showing that there
11

is no genuine dispute of material fact.” Ask Chems., LP v. Comput. Packages, Inc., 593 Fed. Appx
506, 508 (6th Cir. 2014). The moving party may satisfy this initial burden by “identifying those parts
of the record which demonstrate the absence of any genuine issue of material fact.” Lindsey v.
Whirlpool Corp., 295 Fed. Appx 758, 764 (6th Cir. 2008). “[I]f the moving party seeks summary
judgment on an issue for which it does not bear the burden of proof at trial,” the moving party may
also “meet its initial burden by showing that ‘there is an absence of evidence to support the
nonmoving party’s case.’” Id. (quoting Celotex Corp. v. Catrett, 477 U.S. 317, 325 (1986)). Once
the moving party satisfies its burden, “the burden shifts to the non-moving party who must then point
to evidence that demonstrates that there is a genuine dispute of material fact for trial.” Ask Chems.,
593 Fed. Appx at 508-09. “[T]he nonmoving party may not simply rely on its pleading, but must
‘produce evidence that results in a conflict of material fact to be solved by a jury.’” MISC Berhad v.
Advanced Polymer Coatings, Inc., 101 F. Supp. 3d 731, 736 (N.D. Ohio 2015) (quoting Cox, 53 F.3d
at 150).
IV.

Analysis
A.

Motion to Strike (Doc. No. 94)

Prior to reaching the merits of the parties’ arguments, the Court will address Bounty Minerals’
Motion to Strike Defendants’ Notice of Supplemental Authority. (Doc. No. 94.) For the following
reasons, this Motion is denied.
As discussed supra, Defendants filed their Motion for Summary Judgment on April 12, 2019;
Bounty Minerals filed a Brief in Opposition on May 3, 2019; and Defendants filed a Reply Brief on
May 17, 2019. (Doc. Nos. 81, 83, 84.) Several months later, on October 30, 2019, Defendants filed
a “Notice of Supplemental Authority,” in which it brought several recent decisions to the Court’s
12

attention and summarized the facts and holdings of those decisions. (Doc. No. 93.) Bounty Minerals
moved to strike Defendants’ Notice, arguing that it was inappropriate and “nothing more than an
improper attempt by Defendants to have ‘another bite at the apple’ through further legal argument in
a case where briefing ended on May 17, 2019.” (Doc. No. 95-2 at p. 1.)
The Court declines to strike Defendants’ Notice. Defendants do not engage in further legal
argument in their Notice but, rather, simply notify the Court of recent relevant authority and
summarize the findings and holdings of those cases. Moreover, even if Defendants’ Notice could be
construed as including legal argument, Bounty Minerals sets forth legal argument in its Motion to
Strike as to why it believes the newly cited cases are not relevant to the instant dispute.
Courts within this Circuit have noted that motions to strike are disfavored because they are a
“drastic remedy.” Braun v. Ultimate Jetcharters, Inc., 2014 WL 12584328 at * 1 (N.D. Ohio Feb. 25,
2014) (quoting Resolution Trust Corp. v. Vanderweele, 833 F. Supp. 1383, 1387 (N.D. Ind. 1993)).
See also Brown & Williamson Tobacco Corp. v. United States, 201 F.2d 819, 822 (6th Cir. 1953)
(finding that “the action of striking a pleading should be sparingly used by the courts. . . It is a drastic
remedy to be resorted to only when required for the purposes of justice.”). See also Frisby v. Keith
D. Weiner & Associates Co., LPA, 669 F.Supp.2d 863, 865 (N.D. Ohio 2009); Bouchard v. American
Home Products Corp., 2002 WL 32597993 at * 1 (N.D. Ohio July 8, 2002). Here, the Court finds
that this litigation would be better served through resolution of the issues on the merits rather than
through a motion to strike. Accordingly, Bounty Minerals’ Motion to Strike (Doc. No. 94) is denied.
B.

Motion for Summary Judgment

Defendants move for summary judgment in their favor with respect to each of the three counts
raised in the Second Amended Complaint. The Court will address each Count in turn, below.
13

1.

Count I—Breach of Contract against all Defendants based on the alleged
breach of the Royalties Provisions

In Count I, Bounty Minerals asserts a claim for breach of contract of the Lease royalty
provisions. Specifically, Bounty Minerals alleges that “Chesapeake Exploration has engaged in
activities which result in an incorrect valuation point for the royalty and Chesapeake Operating has
failed to tender full and complete royalty payments to Bounty, which are required under the Leases.” 8
(Doc. No. 36 at ¶ 69.)
Defendants argue that they are entitled to summary judgment in their favor with respect to
this claim because they have “complied with the unambiguous terms of the Leases” with respect to
the payment of gas and oil royalties. (Doc. No. 81-2 at pp. 8-15.) As set forth supra, the gas royalty
provision language relevant to this Count provides that Defendants agree to pay a certain percentage
of royalties to Bounty Minerals as follows:
. . . based upon the gross proceeds paid to Lessee for the gas marketed and used off
the leased premises, including casinghead gas or other gaseous substance, and
produced from each well drilled thereon, computed at the wellhead from the sale of
such gas substances so sold by Lessee in an arms-length transaction to an
unaffiliated bona fide purchaser, or if the sale is to an affiliate of Lessee, the price
upon which royalties are based shall be comparable to that which could be
obtained in an arms- length transaction (given the quantity and quality of the gas
available for sale from the leased premises and for a similar contract term) and
without any deductions or expenses. For purposes of this Lease, "gross proceeds"
means the total consideration paid for oil, gas, associated hydrocarbons, and
marketable by-products produced from the leased premises without deductions of any
kind except as provided in paragraph 44.
See, e.g., Ryland Lease at ¶ 9 (Doc. No. 36-4)

8

Bounty asserts that: “The subsequently assigned value of [the alleged sale of hydrocarbons from Chesapeake Exploration
to CEM], which is a derivative value arrived at after-the-fact based on a sales price and post-production costs which are
unknown at the time of the purported ‘sale’ does not represent the ‘total consideration’ paid for the sale of the oil and gas.
Rather, the value assigned to the ‘sale’ between Chesapeake Exploration and CEMLLC is ‘net’ of post-production costs.
This is not a ‘gross proceeds’ royalty.” (Id. at ¶ 64.)

14

Defendants maintain that the above language “unambiguously provides that Chesapeake
Exploration must calculate Bounty Minerals’ royalties based on the value of the gas ‘at the
wellhead.’” (Doc. No. 81-2 at p. 9) (emphasis in original). Citing both state and federal case law,
Defendants assert that the netback method is properly used to determine the wellhead value of the
gas, including the deduction of post-production costs. (Id. at pp. 9-11.) Defendants argue that Bounty
Minerals’ alternative proposed construction of the Leases “would ignore the ‘at the wellhead’
language in direct violation of Ohio law.” (Id. at p. 12.) Thus, Defendants assert that they are entitled
to judgment in their favor with respect to this Count as a matter of law.
Bounty Minerals argues that Defendants’ Motion must be denied “because it is premised on
an incorrect contention that the Leases compel the royalty paid to Bounty to be calculated at the
‘wellhead.’” (Doc. No. 83 at p. 4.) To the contrary, Bounty Minerals maintains that the Leases’
“reference to the ‘wellhead’ as the point of royalty calculation is not applicable to affiliate sales.”
(Id.) Parsing out and examining in detail each of the clauses in the royalty provisions at issue, Bounty
Minerals maintains that the clause containing the reference to the wellhead is “bracketed by commas
which delineate the extent of its reach and applicability—to unaffiliated bona fide third party sales.”
(Id. at p. 8-9.) As Chesapeake Exploration only sells hydrocarbons from the wells to its affiliate,
CEM, Bounty Minerals maintains that the reference to the wellhead “is not germane to this matter.”
(Id. at p. 9.)
Rather, Bounty Minerals focuses on the third clause of the gas royalty provisions and argues
that it “describes a different mechanism for calculating ‘how’ to pay a royalty based on a different
type of sale—by the lessee to an affiliate.” (Id.) This clause provides that: “ . . . , or if the sale is to
an affiliate of Lessee, the price upon which royalties are based shall be comparable to that which
15

could be obtained in an arms - length transaction (given the quantity and quality of the gas available
for sale from the leased premises and for a similar contract term) and without any deductions or
expenses.” Focusing on the comma that precedes this clause, and the use of the word “or,” Bounty
Minerals asserts that this clause is clearly separate from the “unaffiliated sales” clause where the
“computed at the wellhead” language is found. (Id. at p. 11.) Bounty Minerals maintains that the
Defendants’ reading of the Leases “inserts language into the royalty provision where it does not exist”
and argues that “the Defendants cannot bootstrap a method of calculation from one clause onto
another when the contract does not specify it.” (Id. at p. 13.)
Bounty Minerals then goes on to argue that what it terms “the affiliate sales clause” of the
Leases requires that royalties be “comparable to that which could be obtained in an arms-length
transaction . . . and without any deductions or expenses.” (Id.) It asserts that, under this language,
royalties should be calculated based on downstream values, explaining as follows:
For the comparison required by the "affiliate sales" clauses to be effective and a
"comparable price" determined, there must be symmetry between the hydrocarbon
products to ensure that an "apples to apples" comparison is performed. Chesapeake
Exploration transfers title of "wet" gas 9 to CEMLLC at the custody meter, located near
the Wells. At that time and location, the residue gas and NGLs have not been
extracted from the gas stream. The Defendants acknowledge that the gas products
which CEMLLC sells (and upon which royalties are paid to Bounty) are "chemically
distinct" from the "raw products extracted at the wellhead." The "raw products" at the
"wellhead" are not "available for sale" as required by the Leases' "affiliate sales"
clauses. The prices reflected in Bounty's royalty are based on processed products
sold downstream of the wellhead and it is those products at those locations which
are how the comparison must be performed under the "affiliate sales" clause.

9

According to Bounty Minerals’ expert, Phyllis Bourque: “Raw gas or natural gas produced at the wellhead containing
NGLs (such as ethane, propane, and butane), water and other contaminants, which include nitrogen and hydrogen sulfide
is considered ‘wet’ and typically will have a Btu content of 1,100 to 1,300 Btu per cubic foot. The raw gas must be
stripped of the NGLs and the contaminants, which reduces the Btu level and creates ‘dry’ gas also known as residue gas
in order to be suitable for markets and transportation in interstate and intrastate pipelines.” (Doc. No. 78-2 at p. 4.)

16

(Id. at p. 14) (emphasis added) (internal citations to the record omitted).
In response, Defendants argue that Bounty Minerals’ construction of the Lease language is
without merit because “there is no language in the Leases whatsoever providing that royalties are to
be based on a valuation point ‘downstream of the wellhead.’” (Doc. No. 84 at p. 2.) Rather,
Defendants insist that, reading the royalty provision as a whole, the plain language of this provision
clearly provides that the only valuation point is “at the wellhead,” regardless of whether the sale is
made to an unaffiliated or affiliated entity. (Id.) Defendants further assert that Bounty Minerals’
interpretation would yield absurd results because it would cause Bounty Minerals to receive different
royalty payments for the exact same gas depending on who buys it. (Id.) Specifically, Defendants
argue as follows:
In Bounty Minerals’ view, Bounty Minerals should receive royalties based on a
higher, downstream value when gas is sold to an affiliate, and a lower, at-the-wellhead
value when gas is sold to an unaffiliated third party. That gets the Leases precisely
backwards: the whole point of the Lease language is to ensure that royalty valuation
does not turn on the identity of the buyer—i.e., that royalties are not lower when the
gas is sold to an affiliate.
(Id.)
The Ohio Supreme Court has held that oil and gas leases are contracts and “’the rights and
remedies of the parties to an oil or gas lease must be determined by the terms of the written
instrument.’” Lutz v. Chesapeake Appalachia, LLC, 71 N.E.3d 1010, 1012 (Ohio 2016) (quoting
Harris v. Ohio Oil Co., 48 N.E. 502, 506 (Ohio 1897)). “Under Ohio law, the interpretation of written
contract terms, including the determination of whether those terms are ambiguous, is a matter of law
for initial determination by the court.” Savedoff v. Access Grp., Inc., 524 F.3d 754, 763 (6th Cir.2008)
(citations omitted). See also Alexander v. Buckeye Pipe Line Co., 374 N.E.2d 146, 148 (Ohio 1978);
Lutz v. Chesapeake Appalachia, LLC, 2017 WL 4810703 at * 6 (N.D. Ohio Oct. 25, 2017).
17

“It is a well-known and established principle of contract interpretation that ‘[c]ontracts are to
be interpreted so as to carry out the intent of the parties, as that intent is evidenced by the contractual
language.’” Lutz, 71 N.E.2d at 1012 (quoting Skivolocki v. E. Ohio Gas Co., 313 N.E.2d 374 (Ohio
1974)). See also United States Fid. & Guar. Co. v. St. Elizabeth Med. Ctr., 716 N.E.2d 1201, 1208
(Ohio Ct. App. 2nd Dist. 1998). To that end, courts should:
examine the contract as a whole and presume that the intent of the parties is reflected
in the language of the contract. In addition, [courts should] look to the plain and
ordinary meaning of the language used in the contract unless another meaning is
clearly apparent from the contents of the agreement. When the language of a written
contract is clear, a court may look no further than the writing itself to find the intent
of the parties.
Eastham v. Chesapeake Appalachia, LLC, 754 F.3d 356, 361 (6th Cir. 2014) (quoting Sunoco, Inc.
(R&M) v. Toledo Edison Co., 953 N.E.2d 285, 292 (Ohio 2011)). Courts may examine extrinsic
evidence to ascertain the parties' intent only if the contract is ambiguous. Id. See also Shifrin v.
Forest City Enters., 597 N.E.2d 499, 501 (Ohio 1992).
“Ambiguity exists only when a provision at issue is susceptible of more than one reasonable
interpretation.” Lager v. Miller–Gonzalez, 896 N.E.2d 666, 669 (Ohio 2008); see also Lutz, 2017
WL 4810703 at * 7; 11 Williston on Contracts § 30:5 (4th ed.). “[W]hen circumstances surrounding
an agreement invest the language of the contract with a special meaning, extrinsic evidence can be
considered in an effort to give effect to the parties’ intention.” Martin Marietta Magnesia Specialties,
LLC v. Pub. Util. Comm’n, 954 N.E.2d 104, 111 (Ohio 2011). However, as the Ohio Supreme Court
has cautioned, “[o]nly when a definitive meaning proves elusive should rules for construing
ambiguous language be employed. Otherwise, allegations of ambiguity become self-fulfilling.” State
v. Porterfield, 829 N.E.2d 690, 692–93 (Ohio 2005). See also Eastham, 754 F.3d at 361.

18

Here, the key issue is whether the phrase “computed at the wellhead” applies both to sales to
(1) “unaffiliated bona fide purchasers,” and (2) affiliated entities such as CEM. As set forth above,
Bounty Minerals argues that it does not. For the following reasons, the Court disagrees with Bounty
Minerals’ interpretation of the royalty provision. Bounty Minerals divides the royalty provision into
three separate clauses and asks the Court to construe the third clause (i.e., the clause regarding sales
to affiliates) independently from the second clause (i.e., the clause regarding sales to unaffiliated,
bona fide purchasers). Indeed, as counsel for Bounty Minerals repeatedly explained during oral
argument, it is Bounty Minerals’ position that this Court should entirely ignore the second clause of
the gas royalty provision when applying the third clause, rendering the “at the wellhead” language
irrelevant. It is well-established, however, that a contract should be construed to give effect to all of
its provisions. Eastham, 754 F.3d at 363 (“A contract must be construed in its entirety and in a
manner that does not leave any phrase meaningless or surplusage”). The Court is unwilling to
construe the gas royalty provision so as to render the entirety of the second clause of that provision
superfluous. See also Filicky v. American Energy-Utica, LLC, 645 Fed. Appx. 393, 398 (6th Cir.
2016) (“We generally seek to ‘avoid interpreting contracts to contain superfluous words.’”) (quoting
TMW Enters, Inc. v. Fed. Ins. Co., 619 F.3d 574, 578 (6th Cir. 2010)).
Moreover, construing the provision to ignore the second clause (as urged by Bounty) is
problematic because it creates uncertainty regarding the valuation of royalties based on affiliate sales.
Under Bounty Minerals’ construction, the royalty provision’s reference to “at the wellhead” in the
second clause applies only to sales to unaffiliated purchasers and not to sales to affiliates and,
therefore, the netback method does not apply to affiliate sales. By reading the contract in this fashion,
Bounty Minerals creates a gap in the royalty provision with regard to the location and methodology
19

by which affiliate sales are to be computed. Specifically, if the “at the wellhead language” is severed
from the affiliate sales clause as argued by Bounty Minerals, there is no language in the royalty
provision denoting where or how the royalties from affiliate sales shall be computed. Bounty
Minerals argues that royalties should be based on the downstream sales values with no deductions
for post-production costs. However, Bounty Minerals points to no language in the royalty provision
that would support this interpretation. Bounty Minerals’ construction of the royalty provision creates
a hole in the contract, which it then fills (without any citation to supporting language in the contract)
with the construction that would provide it with the highest royalties.
The Court is not persuaded that the royalty provision at issue should be read in such a manner.
Rather, the Court finds that the royalty provision should be read as a cohesive whole, giving effect
and meaning to all of its terms. Reading the royalty provision in its entirety, it is plain that it creates
only one valuation point for both unaffiliated and affiliated sales; i.e., “at the wellhead.” While the
presence of the comma highlights that there are two different possible types of sales (i.e., sales to
unaffiliated vs. affiliated entities), the Court finds that the comma does not, standing alone, result in
the creation of a separate (and undefined) location and/or methodology for calculating the value of
the hydrocarbons with respect to affiliate sales. As discussed above, to read the royalty provision as
urged by Bounty Minerals would create a gap and insert an entirely different valuation point and
methodology for affiliated sales, a result which is simply not supported by the language of the royalty
provision at issue. Indeed, Bounty Minerals has not pointed to any language in the Leases that could
reasonably be construed as providing that royalties are to be based purely on downstream values. 10

10

Although not expressly argued by Bounty, the Court finds that its construction of the royalty provision is not
contradicted by the inclusion of the language “without any deductions or expenses” at the end of the affiliate sales clause.
Specifically, the royalty provision states that the Lessee (i.e., Chesapeake Exploration) covenants and agrees that, “if the

20

Moreover, under Bounty Minerals’ interpretation, Bounty would receive royalties based on a
higher, downstream value (with no subtraction of post-production costs) when the gas is sold to an
affiliate; and a lower, at-the-wellhead value when the gas is sold to an unaffiliated third party.
However, the royalty provisions are plainly designed to ensure that that prices relative to affiliated
sales are “comparable” to prices obtained in unaffiliated sales. Indeed, the royalty provisions state
exactly that. As set forth above, the Leases expressly provide that, for affiliate sales, “the price upon
which royalties are based shall be comparable to that which could be obtained in an arms-length
transaction.” The clear import of this language is that royalties based on unaffiliated and affiliated
sales should be equivalent to one another. Under Bounty Minerals’ reading of this provision,
however, royalties based on unaffiliated sales and affiliated sales would not be equivalent. Bounty
Minerals’ construction of the royalty provisions, then, would lead to a result that is not consistent
with the plain language of the Lease.

sale is to an affiliate, the price upon which royalties shall be based shall be comparable to that which could be obtained
in an arms-length transaction . . . and without any deductions or expenses.” Read in context, the Court finds that this
language prohibits deductions by Chesapeake Exploration after CEM has computed royalties at the wellhead and
transferred the proceeds to Chesapeake Exploration for royalty payments. Importantly, and as discussed infra, the
computation of royalties at the wellhead via the netback method presupposes that deductions are taken for post-production
costs. Those deductions, however, are taken by CEM and not by Chesapeake Exploration and, thus, do not fall within
the “without any deduction or expenses” language in the affiliate sales clause. Rather, this language prohibits Chesapeake
Exploration from making deductions once it has received the proceeds from CEM from its downstream sales to thirdparty purchasers, such as deductions for production and/or marketing costs. This interpretation is consistent with the
Sixth Circuit’s decision in EQT Productions Co. v. Magnum Hunter Co., 768 Fed. Appx. 459, 466-467 (6th Cir. 2019).
In that case, the Sixth Circuit considered contractual language that did not set the place of market or the price, but provided
for royalties “without deductions of any kind.” Id. Applying Kentucky law, the court found that application of the atthe-well rule was appropriate. The court explained as follows: “a prohibition on deductions simply does not explain
where gas is to be sold or for how much—the two pieces of information Kentucky courts have explained could halt
application of the at-the-well rule. Further, application of the at-the-well rule does not render the prohibition on
deductions meaningless. Magnum Hunter remains unable to deduct ‘production costs, like those incurred drilling,
operating and maintaining a well, as well as other costs incurred in order to extract gas from the earth and bring it up to
the wellhead.’” Id. (quoting Poplar Creek Dev. Co. v. Chesapeake Appalachia, 636 F.3d 235, 239 (6th Cir. 2011)).
Although the Sixth Circuit applied Kentucky law in EQT, the court’s reasoning with regard to this particular issue is
persuasive herein.

21

For similar reasons, the Court agrees with Defendants that Bounty Minerals’ proposed
construction would lead to an absurd result. Ohio courts have found that “parties bind themselves to
the plain and ordinary language used in a contract unless those words lead to a manifest absurdity.”
Fultz & Thatcher v. Burrows Group Corp., 2006 WL 3833971 at * 2 (Ohio App. 12th Dist. Dec. 28,
2006) (citing Alexander v. Buckeye Pipe Line Co., 374 N.E.2d 146 (Ohio 1978)). Even assuming
that Bounty Minerals’ literal construction of the sentence at issue had some merit, it would lead to
the incongruous result that sales to unaffiliated entities (i.e., arms-length transactions) would result
in lower royalties than sales to affiliated entities. Bounty Minerals offers no logical explanation as
to why the parties would contract for such a result, and the Court can think of none. Indeed, as
discussed above, the purpose of the royalty provisions at issue is to create parity between royalties
derived from unaffiliated and affiliated sales. Bounty Minerals’ interpretation of the lease would
undermine this purpose and is not supported by either the express language of the royalty provisions
or common sense.
Accordingly, and for all the reasons set forth above, the Court rejects Bounty Minerals’
interpretation of the lease and agrees with Defendants that the plain language of the relevant gas
royalty provisions provides that Defendants must calculate Bounty Minerals’ royalties based on the
value of the gas “at the wellhead,” with respect to both unaffiliated and affiliated sales. Notably,
Bounty Minerals does not dispute that (1) Chesapeake Exploration’s transfer of the hydrocarbons to
CEM constitutes a “sale to an affiliate” under the Lease; 11 or (2) Defendants calculated the value of

11

In Count I, Bounty Minerals asserts that Chesapeake Exploration’s transfer of oil and gas to CEM “is not a ‘sale’ or an
actual, bona fide transfer” but, instead, is “merely an artificial sham transaction.” (Doc. No. 36 at ¶ 63.) Bounty Minerals
does not raise this issue in its Brief in Opposition and makes no argument that summary judgment with respect to this
Count should be denied on this basis. Thus, the Court deems this issue waived and does not address it herein.

22

the hydrocarbons “at the wellhead.” 12 Therefore, the Court finds that Bounty Minerals has failed to
demonstrate that Defendants breached the gas royalty provisions of the relevant leases.
Defendants also move for summary judgment with respect to the oil royalty lease provisions.
As noted supra, the oil royalty provisions differ among the various leases. During oral argument, the
parties appeared to agree 13 that the Ryland, Ritchie, and Ingham oil royalty provisions are similar to
the gas royalty provisions discussed above, and that the same arguments in favor of their various
proposed constructions of the gas royalty provisions apply to these oil royalty provisions. The Court
notes that the Ryland, Ritchie, and Ingham oil royalty provisions do not contain the “computed at the
wellhead” language set forth in the second clause of the gas royalty provisions at issue. Rather, the
Ryland, Ritchie, and Ingham oil royalty provisions state that the royalty shall be based upon the gross
proceeds paid to Lessee from the sale of oil “recovered from the leased premises so sold by Lessee
in an arms-length transaction to an unaffiliated bona fide purchaser, or if the sale is to an affiliate of
Lessee, the price upon which royalties are based shall be comparable to that which could be obtained
in an arms-length transaction (given the quantity and quality of said products available for sale from

12

Bounty Minerals does not argue that the Ohio Supreme Court would not recognize the “at the wellhead” rule. The
Court notes that, in Lutz, another court within this District found that “the Ohio Supreme Court would adopt the ‘at the
well’ rule, simply applying the clear and unambiguous language in the leases.” Lutz, 2017 WL 4810703 at * 7. In that
case, the court found that “the use of the . . . language, ‘market value at the well’ ‘appears meaningless in isolation because
the gas is not sold at the wellhead and, thus, there are no proceeds at the wellhead.’” Id. (quoting Schroeder v. Terra
Energy, 565 N.W.2d 887, 891 (Mich. App. 1997)). “However, if the term is understood to identify the location at which
the gas is valued for purposes of calculating a lessor’s royalties, then the language . . . becomes clearer and has a logical
purpose in the contract.” (Id.) In the instant case, however, Defendants have argued and introduced evidence that there
is, in fact, an active wellhead market for gas and oil in Ohio. (Doc. No. 81-2 at p. 14.) Bounty Minerals disputes this
contention. See Expert Report of Phyllis Bourque (Doc. No. 78-2 at p. 19) (“It is my opinion that the first location the
Utica wet gas is marketable and is marketed to an unaffiliated bona fide purchaser(s) occurs after the gas has been
gathered, dehydrated, processed, and compressed and meets the quality specifications of the interstate and intrastate
pipelines that transport the gas to consumers.”) As Bounty Minerals does not challenge the use of the “at the wellhead”
rule, the Court deems that issue waived and does not address it herein.
13

Neither party clearly addresses the oil royalty lease provisions in their summary judgment briefing.

23

the leased premises and for a similar contract term) and without any deductions or expenses.” (Doc.
Nos. 36-4, 36-8, 36-10.)
Defendants argue, and the Court agrees, that the language “recovered from the leased
premises” as used in the above provision sets the valuation point for sales to both unaffiliated and
affiliated purchasers. The Court also agrees that the phrase “recovered from the leased premises”
contemplates valuation at the well and, therefore, authorizes the deduction of post-production costs,
for all of the reasons discussed above.
With regard to the Miller and Cobbs leases, the oil royalty provisions of those leases provide
that the royalty shall be based “upon the gross proceeds paid to Lessee from the sale of oil recovered
from the lease premises valued at the purchase price received for oil prevailing on the date such oil
is run into transporter trucks or pipelines.” (Doc. Nos. 36-2 at PageID#s 1684, 1704; 36-6.) The
Court likewise finds that the phrase “recovered from the leased premises” denotes valuation at the
well. Moreover, construing similar contract language, at least one court has found that the phrase
“run into transporter trucks or pipelines” similarly indicates valuation at the well. See Burlington
Resources Oil & Gas Co. LP v. Texas Crude Energy, LLC, 573 S.W.3d 198, 207-208 (Texas S.Ct.
2019). Accordingly, and in the absence of any meaningful argument to the contrary, the Court finds
that Bounty Minerals has failed to demonstrate that Defendants breached the oil royalty provisions
of the relevant leases.
Therefore, and for all the reasons set forth above, Defendants are entitled to summary
judgment in their favor with respect to Count I of the Second Amended Complaint.
2.

Count II—Breach of the Express Covenants of Good Faith and
Reasonable Prudent Operator

24

In Count II, Bounty Minerals alleges that Defendant Chesapeake Exploration violated the
Leases’ express covenants of good faith and reasonable prudent operator. Bounty asserts that “the
sole purpose of Chesapeake Exploration’s interaction with [CEM] is to avoid Chesapeake
Exploration’s obligation to carry the lessors’ hypothetical share of post-production costs, which is
dictated by the Leases’ royalty clauses.” (Doc. No. 36 at ¶ 79.) Bounty claims that “[i]n essence,
Chesapeake Exploration decided to engage in a ‘gift’ transaction to an affiliate solely in order to
escape and/or avoid responsibility for paying Bounty’s hypothetical share of post-production costs
under the Leases.” (Id. at ¶ 91.) Bounty alleges that “a reasonable prudent operator would not transfer
title to and possession of a commodity to any other party without a valuation of the commodity at the
location and time of the sale and without any firm commitment that it receive payment of a certain
value after the alleged transaction concludes.” (Id. at ¶ 93.)
Defendant Chesapeake Exploration argues it is entitled to judgment in its favor with respect
to this claim because “there is no evidence in the record that [it] has not acted in an ‘ordinarily
prudent’ way or in bad faith in entering into contracts with CEMLLC, selling at the wellhead to
CEMLLC, or paying royalties to Bounty Minerals based on the netback method.” (Doc. No. 81-2 at
p. 15.) It asserts that royalties are paid as required by the Leases and notes that the netback method
(pursuant to which post-production costs are deducted) has been approved by numerous courts. (Id.)
Chesapeake Exploration also cites evidence that its method of calculating royalties is typical in the
industry, as is the practice of selling to an affiliate. (Id. at p. 16.)
In its Brief in Opposition, Bounty Minerals appears to abandon its claim that Chesapeake
Exploration violated the covenant of good faith/reasonable prudent operator by engaging in a “sham”
or “gift” transaction to its affiliate, CEM. (Doc. No. 83 at pp. 18-19.) Instead, Bounty advances a
25

new theory, arguing that Chesapeake Exploration violated the covenant of good faith by sending
revenue statements that falsely give the impression that there were no deductions and that the royalty
is a “gross” royalty that is paid without deduction. (Id. at p. 19.) Bounty Minerals further asserts that
Chesapeake Exploration’s “royalty calculation is not in good faith” because it includes deductions
and costs related to activities that occur after title to the gas has been transferred, citing Pollock v.
Energy Corp. of America, 2015 WL 3795659 (W.D. Pa. June 18, 2015).
In response, Chesapeake Exploration first notes that Bounty Minerals’ argument regarding
the allegedly deceptive royalty statements is not presented as a basis for its good faith/reasonable
prudent operator claim as set forth in Count II. (Doc. No. 84 at fn 4.) Chesapeake Exploration then
argues that this new argument is without merit because (1) “the check stubs accurately reflect the
undisputed fact that Chesapeake Exploration has not taken any deductions from Bounty Minerals’
royalty payments;” and (2) Chesapeake Exploration has, in fact, paid royalties in accordance with the
Leases and both federal and state case law. (Id. at p. 8.) Lastly, Chesapeake Exploration argues that
Bounty Minerals’ reliance on Pollock Energy is misplaced because, in that case, the operator retained
title to the oil and gas until sale to third-party buyers by its affiliate, but certain costs to make that
sale were incurred only by the affiliate. (Id. at p. 9.) In the instant case, however, Chesapeake
Exploration does not retain title to the oil and gas and, further, any marketing fees incurred by CEM
are not passed on to Bounty Minerals. (Id. at pp. 9-10.)
As set forth above, each of the Leases at issue impose an obligation on the Lessee to act “as
a reasonable prudent operator exercising good faith in all of its activities with the Lessor.” See Doc.
Nos. 36-2 at PageID# 1683, 1703; 36-4 at PageID# 1731; 36-6 at PageID# 1757; 36-8 at PageID#

26

1787; 36-10 at PageID# 1817. The “reasonable prudent operator” standard was recently explained
by one Ohio appellate court, as follows:
The reasonable prudent operator standard in oil and gas cases is similar to the
reasonable person standard in tort cases. It is the “standard by which all actions taken
by the lessee in the production and operation of the wells on the leasehold are judged.”
Hardymon, Adrift on the Implied Covenant to Market: Regulation by Implication, 24
Energy & Min.L.Inst. 8.02 (2004). Research shows that few Ohio cases mention the
standard, but they do not develop the standard. See Holonko v. H.D. Collins, 7th Dist.
Mahoning No. 87 C.A. 120, 1988 WL 70900 (June 29, 1988); State v. Baldwin
Producing Corp., 10th Dist. Franklin No. 76AP–892, 1977 WL 199981 (March 10,
1977); Rayl v. East Ohio Gas Company, 46 Ohio App.2d 167, 348 N.E.2d 385 (9th
Dist.1973).
When applied, the reasonable prudent operator standard is utilized to judge whether
the lessee was completing the implied covenants to explore, develop, produce, and
market as any reasonably prudent operator would do under the circumstances. Rayl,
supra at 171, 348 N.E.2d 385. The reasonable prudent operator standard “may not be
an implied covenant per se, but an overreaching standard of performance with which
the lessee must comply in fulfilling all of his obligations, express or implied.”
Hardymon, supra at 8.02.
Yoder v. Artex Oil Co., 2014 WL 6467477 at * 12-13 (Ohio App. 5th Dist. Nov. 13, 2014).
For the following reasons, the Court finds that Chesapeake Exploration is entitled to judgment
in its favor with respect to Count II. First, the Court rejects Bounty Minerals’ argument that
Chesapeake Exploration acted in bad faith when it submitted revenue statements that allegedly failed
to disclose deductions for post-production costs. Chesapeake Exploration has not, in fact, taken any
deductions from Bounty Minerals’ royalty payments. As explained supra, it is undisputed that
Chesapeake Exploration transferred title to CEM at or near the wellheads. It is further undisputed
that CEM deducted post-production costs and then transferred proceeds to Chesapeake Exploration
based on a netback price. Bounty Minerals has not demonstrated that Chesapeake Exploration took
any deductions from the proceeds that it received from the sale to CEM. Moreover, the Revenue
Statements expressly disclose that the gross value “may reflect the price received from an affiliated
27

purchaser” and, further, that “[d]eductions made by the purchaser (affiliated or non-affiliated)” – i.e.,
CEM— “may or may not be shown.” (Doc. No. 36-12.)
Most importantly, and as discussed at length above, the Court has found that Defendants paid
royalties to Bounty consistent with the Lease royalty provisions when it calculated royalties based on
the value of the gas and oil “at the wellhead.” Defendants correctly note (and Bounty Minerals does
not contest) that numerous courts have interpreted the language “at the well” as unambiguously
allowing for the deduction of post-production costs. See e.g., Cunningham Property Management
Trust v. Ascent Resources- Utica, LLC, 351 F.Supp.3d 1056, 1062 (S.D. Ohio 2018); Lutz, 2017 WL
4810703 at * 7-8. 14
This also defeats Bounty Minerals’ argument that the royalty calculations were “not in good
faith” because they were based on deductions and costs related to activities that occurred after transfer
of title to the gas. Although the Pollock court may have so held under the circumstances of that
particular case, the Ohio Supreme Court has again and again explained that “’the rights and remedies
of the parties to an oil or gas lease must be determined by the terms of the written instrument.’” Lutz,
71 N.E.2d at 1012. See also Harris, 48 N.E. at 506. Here, the Court has carefully considered the
parties’ arguments and interpreted the Leases to find that Defendants paid royalties to Bounty
Minerals consistent with the language of the relevant royalty provisions. As discussed above, under
those provisions, Defendants properly computed royalties “at the wellhead” via use of the netback
method, which allows for the deduction of post-production costs.

14

See also Poplar Creek Dev. Co., 636 F.3d at 244 (“Kentucky follows the ‘at-the-well’ rule, which allows for the
deduction of post-production costs prior to paying appropriate royalties.”); Potts v. Chesapeake Exploration, LLC, 760
F.3d 470, 474 (5th Cir. 2014) (explaining that “Chesapeake could arrive at the market value of the wellhead by deducting
reasonable post-production costs to deliver the gas from the wellhead to the point at which the gas was sold to unaffiliated
purchasers.”)

28

Accordingly, the Court finds that Bounty Minerals has failed to present any evidence that
Chesapeake Exploration has not acted in good faith or as a reasonable prudent operator. Chesapeake
Exploration is, therefore, entitled to summary judgment in its favor with respect to Count II of the
Second Amended Complaint.
3.

Count III—Breach of the Affiliate Sales Provision

In Count III, Bounty Minerals alleges that Defendants breached the royalty provisions of the
subject Leases because “the royalties that Bounty receives for production under the Leases is not
comparable to values that could be obtained in an arms-length transaction and are not ‘without any
deductions or expenses.’” 15 (Doc. No. 36 at ¶ 111.)
Defendants argue that they are entitled to judgment in their favor with respect to this claim
because Bounty Minerals’ royalty payment is directly tied to the arms-length sales price that is
received downstream and is, therefore, “comparable” to the value that could be obtained in an armslength transaction. (Doc. No. 81-2 at p. 17.) Specifically, Defendants argue:
Pursuant to the netback method employed here, CEMLLC calculates a weightedaverage sales price based on downstream sales to unaffiliated third-parties. Ex. 1 at
Resp. to Req. No. 4. That price is then adjusted by subtracting the actual postproduction costs incurred to obtain that higher, downstream sales price. Id.
Chesapeake Exploration has thus fulfilled its obligation to pay a royalty based on a
price “comparable” to that obtained in an arms-length transaction at the wellhead. This
fact alone should end the inquiry.

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In this Count, Bounty Minerals sets forth several examples of “cost free” oil royalties it received from other operators
in the same area that were allegedly greater than that it received from Defendants during the same time frame. (Doc. No.
36 at ¶¶ 113, 114.) As Defendants correctly note, however, Bounty Minerals appears to have abandoned this particular
line of proof. Specifically, Bounty Minerals has not argued or directed this Court’s attention to any evidence in the record
relating to the evidence cited in Paragraphs 113 and 114 of the Second Amended Complaint. Thus, the Court deems any
argument based on these allegations to be waived.

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(Id.) Defendants further assert that they are entitled to judgment because Bounty Minerals has failed
to come forward with any evidence that the sales of oil and gas from the wells at issue were not
comparable to prices that would have prevailed in arms-length transactions with unaffiliated entities
in the same areas. (Id. at p. 18.) Defendants assert that Bounty Minerals’ expert, Phyllis Bourque,
failed to conduct a market value study on this very issue, and argues that the data that Ms. Bourque
did compile relates to prices in Texas, which is not comparable to sales prices in the area of the wells
at issue herein. (Id. at pp. 18-20.)
Bounty Minerals argues that Defendants’ argument fails because “the Leases do not compel
the ‘wellhead’ as the point of royalty valuation.” (Doc. No. 83 at p. 14.) Rather, Bounty’s expert,
Ms. Bourque, determined that the marketplace for “wet” gas is at the interstate pipeline, after it has
been processed. (Id. at p. 15.) Ms. Bourque evaluated the prices paid for pipeline quality gas at
certain locations and determined that “the gas prices paid to Bounty was [sic] lower than and not
comparable to these prices.” (Id.) In calculating damages relating to gas, Ms. Bourque “accepted the
weighted average sales values of residue gas from CEMLLC to third party purchasers and simply
eliminated the post-production costs and fees charged by CEMLLC and her Supplemental Report
identifies over $300,000 in damages for residue gas and [natural gas liquids].” (Id.) Ms. Bourque’s
damages calculations with regard to oil royalties “were rooted in the West Texas Intermediate
benchmark price.” (Id. at p. 18.)
In response, Defendants argue that Bounty Minerals has failed to establish a genuine issue of
material fact because “the comparable price that matters here is the price obtained in an arms-length
transaction at the wellhead.” (Doc. No. 84 at p. 6) (emphasis added). They maintain that “neither
Bounty Minerals nor its expert present any comparable prices to those obtained in an arm’s length
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transaction at the wellhead—instead, Bounty Minerals relies on a downstream price that is irrelevant
given the lease language.” (Id.)
The Court agrees with Defendants. Bounty Minerals’ royalties were properly calculated at
the wellhead via the netback method. As such, Bounty Minerals’ royalty payments were directly
derived from sales made by CEM in arms-length transactions with unaffiliated, third-party
purchasers. As such, the Court finds there is no genuine issue of material fact that these sales prices
that formed the basis of Bounty Minerals’ royalty payments are not “comparable” to “values that
could be obtained in an arms-length transaction.” Moreover, the Court agrees with Defendants that
the findings of Bounty Minerals’ expert, Ms. Bourque, do not compel a different conclusion because
Ms. Bourque’s analysis was not based on calculations “at the wellhead” and use of the netback
method, which this Court has found proper for all the reasons set forth above.
Accordingly, the Court finds that Defendants are entitled to summary judgment in their favor
with respect to Count III of the Second Amended Complaint.
V.

Conclusion
For all the reasons set forth above, Plaintiff’s Motion to Strike (Doc. No. 94) is DENIED, and

Defendants’ Motion for Summary Judgment (Doc. No. 81) is GRANTED.
IT IS SO ORDERED.

s/Pamela A. Barker
PAMELA A. BARKER
U. S. DISTRICT JUDGE

Date: December 23, 2019

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