IN THE UNITED STATES BANKRUPTCY COURT September 14, 2021 FOR THE SOUTHERN DISTRICT OF TEXAS Nathan Ochsner, Clerk HOUSTON DIVISION
IN RE: § § CASE NO: 20-33233 CHESAPEAKE ENERGY § CORPORATION, et al., § CHAPTER 11 § Debtors. § § PETTY BUSINESS ENTERPRISES, L.P., et § al., § § Plaintiffs, § § VS. § ADVERSARY NO. 20-3433 § CHESAPEAKE EXPLORATION, L.L.C., et § al., § § Defendants. §
MEMORANDUM OPINION (Docket No. 44)
In this adversary proceeding, Petty Business Enterprises, L.P. and multiple principals, beneficiaries and affiliates (collectively, “Petty”) seek money damages against the defendants arising out of a series of oil and gas leases. The Court previously granted partial relief by summary judgment. Further and as set forth below, the parties consensually resolved several additional claims both prior to and during trial. This memorandum opinion (i) addresses Petty’s remaining claims; (ii) directs the parties to confer and perform certain arithmetical calculations; (iii) requires the parties to prepare and submit a proposed form of judgment consistent with this memorandum opinion; and (iv) orders payment from funds reserved under the confirmed plan in the main bankruptcy proceeding.
Brief History of the Parties’ Relationship
Petty owns and operates three ranches in South Texas known as the Dos Hermanos Ranch, the Browne Ranch and the Maguey Ranch (the “Ranches”). Beneath the Ranches lies the prolific Eagle Ford Shale formation (the “Eagle Ford”). After the completion of the first successful horizontal oil well in the Eagle Ford in 2008, Chesapeake Exploration, L.L.C. (“Chesapeake Exploration”) entered into a series of mineral leases with Petty covering over 25,000 acres (the “Leases”). To date, Chesapeake Exploration has drilled approximately 87 wells on the Leases. The Leases are virtually identical in their composition and contain several unusual provisions favorable to Petty. Under the Leases, Petty retained a 27½% royalty on all minerals produced as well as the right to acquire a ten percent working interest in each new well drilled by Chesapeake. The Leases provide multiple pricing formulas to be used in calculating the amount of royalty due from the production of specific minerals. Unless stated otherwise, all royalty is calculated before the deduction of costs. Further, the Leases provide that royalty is due on all financial transactions such as swaps and hedges involving extracted minerals. Finally, the Leases require Petty to be treated as a third-party beneficiary to any agreement “affecting the sale, exchange, use, disposition, marketing or transportation” of minerals attributable to the Leases.
Jamestown Resources, LLC (“Jamestown”), Larchmont Resources, LLC (“Larchmont”) and CNOOC Energy U.S.A, LLC (“CEU”) are all assignees of various interests held by Chesapeake Exploration under the Leases.
Procedural History of the Litigation Prior to the Chesapeake Bankruptcies
On April 30, 2020, Petty filed suit against Chesapeake Exploration, Chesapeake Energy Marking, LLC (“Chesapeake Marketing”), Jamestown, Larchmont and CEU in the 285th Judicial District Court of Bexar County, Texas (the “Bexar County Litigation”). [Docket No. 1]. In its original petition, Petty sought money damages related to the alleged underpayment of royalty due under the Leases. [Docket No. 1]. The petition was subsequently amended on several occasions during the state court proceedings. [Docket No. 1].
Chesapeake Energy Corporation and forty affiliates filed voluntary chapter 11 cases on June 28, 2020. [Docket No. 1, Case No. 20-33233]. The cases were designated as complex cases under the Procedures for Complex Cases. [Docket No. 82, Case No. 20-33233]. An order for joint administration was entered on June 28, 2020. [Docket No. 91, Case No. 20-33233]. Both Chesapeake Exploration and Chesapeake Marking (collectively “Chesapeake”) are debtors in the jointly administered cases. [Docket No. 91, Case No. 20-33233].
On September 23, 2020, the Bexar County Litigation was removed to the United States District Court for the Western District of Texas and referred to the United States Bankruptcy Court for the Western District of Texas. [Docket No. 1]. By Order entered September 25, 2020, the Bexar County Litigation was transferred to the United States District Court for the Southern District of Texas. [Docket No. 6]. Pursuant to General Order 2012-6, the Bexar County Litigation was automatically referred to this Court. The case was officially transferred and docketed on October 5, 2020. [Docket No. 9].
Proceedings before the Bankruptcy Court
Upon the transfer and docketing of the Bexar County Litigation, the defendants filed amended answers. [Docket Nos. 10, 11 and 13]. On December 18, 2020, Petty filed its opposed motion for leave to amend its complaint. [Docket No. 18]. Based on subsequent stipulations between the parties [Docket Nos. 36 and 37], Petty filed a second agreed motion for leave to amend its complaint on February 4, 2021. [Docket No. 30]. The amended complaint was attached as an exhibit to Docket No. 37. The Court confirmed the Debtors’ plan of reorganization (the “Plan”) in the main bankruptcy case by Order entered January 16, 2021. [Case 20-33233, Docket No. 2915]. The Plan became effective February 9, 2021. [Case 20-33233, Docket No. 3058]. As part of the confirmation process, the parties agreed to a series of stipulations and settlements regarding certain of Petty’s claims. [Case 20-33233, Docket Nos. 2915 and 3810].
On March 8, 2021, the Court approved the parties’ stipulation to amend Petty’s complaint to reflect the agreements reach in connection with Plan confirmation. [Docket No. 46] (the “Amended Complaint”). The current version of the Amended Complaint is found at Docket No. 44. The Amended Complaint identifies the following claims against all defendants:
- Breach of Contract – Audit Period 2016-2017.
- Breach of Contract – Audit Period January 2018 to June 2020.
- Breach of Duty of Good Faith and Fair Dealing.
- Breach of Fiduciary Duty.
- Non-Payment of Proceeds under Texas Natural Resources Code.
- Declaratory Judgment – 28 U.S.C. § 2201.
- Attorney’s and Expert’s Fees.
- Interest on all amounts due at 18%.
[Docket No. 44]. Within the breach of contract claims, Petty asserted that the defendants failed to properly calculate and pay royalty under the Leases in the following ways:
- Failed to pay royalty on hedging and derivative transactions (the “Financial Derivatives Claim”).
- Failed to pay royalty on 100% of produced oil, condensate, and liquid hydrocarbon volumes.
- Failed to pay royalty for skim oil volumes recovered from produced saltwater.
- Failed to pay royalty on 100% of reported gas volumes.
- Failed to pay royalty on unmetered flared gas (the “Flash Gas Claim”).
- Failed to pay royalty on net gas produced by failing to properly account for the gas volumes used for gas lift. - Used improper and unauthorized weighted average sales prices (“WASP”) to calculate and pay royalty for produced oil, gas, and natural gas liquids (the “Highest Price Claim”).
- Improperly deducted costs for gas processing.
- Failed to pay royalty based on the highest price for oil, condensate, and other liquid hydrocarbons in accordance with the multiprong test.
- Failed to pay royalty based on the highest price for gas in accordance with the multi- prong test.
- Failed to pay royalty based on the highest price for plant products in accordance with the multi-prong test.
- Failed to pay royalty based on the highest prices paid for production on or within 50 miles of the leased premises.
- Improperly deducted severance taxes from Petty’s royalty (the “Severance Tax Claim”).
[Docket No. 44].
On March 12, 2021, Chesapeake, CEU, Jamestown and Larchmont filed their motion for partial summary judgment. [Docket No. 48]. In the motion, the movants requested that Petty’s (i) Highest Price Claim; and (ii) Financial Derivatives Claim be denied. [Docket No. 48]. CEU also filed a separate motion for partial summary judgment seeking the denial of the Financial Derivative Claim on the ground that CEU did not engage in any hedging or financial derivative transactions during the relevant period. [Docket No. 49]. Jamestown and Larchmont subsequently joined CEU’s separate motion. [Docket No. 50]. In addition, Chesapeake, CEU, Jamestown and Larchmont filed motions for partial summary judgment on Petty’s Flash Gas Claim [Docket No. 52] and Severance Tax Claim. [Docket No. 53]. Petty filed its own motions for partial summary judgment as to liability only on the Severance Tax Claim [Docket No. 54] and the Financial Derivatives Claim. [Docket No. 55]. Responses and replies were timely filed. [Docket Nos. 62, 63, 64, 65, 66, 70, 71, 72, 73 and 74].
By stipulation and agreed order entered March 29, 2021, Petty dismissed its Financial Derivative Claim against CEU. [Docket No. 67]. By stipulation and agreed order entered April 21, 2021, Petty also dismissed its Financial Derivative Claim against Jamestown and Larchmont. [Docket No. 78].
On April 19, 2021, the Court conducted a hearing on the pending motions for summary judgment. After considering the relevant pleadings, the arguments of the parties and the applicable law, the Court announced its findings and conclusions on the record pursuant to Bankruptcy Rule 7052 and granted partial relief. [Docket No. 94]. Specifically, with respect to Docket No. 48, the Court stated: With respect to the question of whether or not Plaintiffs are entitled to calculate the Gross Proceeds Pricing Prong based upon the highest price realized by Chesapeake Marketing in any of its downstream sales, Defendants’ motion is GRANTED; and
With respect to the question of whether Plaintiffs are entitled to any royalty on the gains realized by Chesapeake Energy Corporation in its financial derivatives transactions, Defendants’ motion is DENIED.
[Docket No. 94]. With respect to the remaining motions for partial summary judgment, the Court took the following actions by Order entered May 13, 2021:
Defendants’ Motion for Summary Judgment on Flash Gas Claim, Dkt. 52, is GRANTED.
Defendants’ Motion for Summary Judgment on Severance Tax Claim, Dkt. 53, is DENIED.
Plaintiffs’ Motion for Partial Summary Judgment—as to Liability Only—on Breach-of-Contract Claim Involving Chesapeake’s Excessive Deductions of Severance [Taxes], Dkt. 54, is GRANTED.
Plaintiffs’ Motion for Partial Summary Judgment—as to Liability Only—on Breach-of-Contract Claim Involving Chesapeake’s Failure to Pay a Royalty on Amounts Realized From Hedging, Dkt. 55, is DENIED.
[Docket No. 94].
On May 13, 2021, Petty filed its motion for leave to amend its complaint to remove the Highest Price Claim and to supplement the expert report of Dave Marshall. [Docket No. 103]. The defendants filed their response on May 16, 2021. [Docket No. 121]. Petty filed its reply the same day. [Docket No. 124]. After the defendants declined the Court’s offer to allow Mr. Marshall to be re-deposed, the Court denied the request to remove the Highest Price Claim but granted the request to supplement Mr. Marshall’s expert report by Order entered May 17, 2021. [Docket No. 126].
By Stipulation approved May 17, 2021, the parties reached the following agreements:
Attorneys’ Fees and Expenses. The parties agree to try Plaintiffs’ claim for attorneys’ and expert fees, see Am. Adv. Complt ¶¶ 125-126, by motion practice in accordance with Federal Rule of Civil Procedure 54(b) after there are written rulings entered on the merits of Plaintiffs’ claims. The Defendants will have 14 days to respond to Petty’s motion. The Court will schedule an evidentiary hearing on the motion to fit its schedule. Interest Rate. The parties agree to try the issue of the correct interest rate under the Leases (10% [Defendants’ position] versus 18% [Plaintiffs’ position]), see Am. Adv. Complt ¶¶ 86, 91, at trial. The parties will meet and confer in light of the Court’s ruling on the correct interest rate and the Court’s rulings on the merits of various claims to attempt to stipulate on the applicable amount of interest; if no stipulation is reached Plaintiffs may bring by motion and Defendants may respond in opposition to Plaintiffs’ interest calculation.
In light of the Court’s order granting Plaintiffs’ Motion for Partial Summary Judgment—as to Liability Only—on Breach-of-Contract Claim Involving Chesapeake’s Excessive Deductions of Severance Taxes (Dkt. No. 94), the parties stipulate that the damages for Plaintiffs’ breach-of-contract claim on Defendants’ deduction of excessive severance taxes (Exception 10) is $3,015,398.65 (exclusive of interest and fees).
[Docket No. 134].
The Court commenced a video trial on May 17, 2021 at 2:00 p.m. (prevailing Central time). After receiving opening statements, the Court heard the live testimony of Scott James Petty and Scott Petty, Jr. [Docket No. 169]. The Court next heard the testimony of David Ownby by video deposition. [Docket No. 169]. At the conclusion of Mr. Ownby’s testimony, the trial was adjourned to May 18, 2021 at 9:00 a.m. (prevailing Central time).
During the second day of trial, the Court heard testimony from Barry Pulliam and Dave Marshal (direct only). [Docket No. 164]. Mr. Marshal’s profession is that of a professional royalty auditor. Mr. Marshal was offered as an expert on the issues of (i) underpayment of royalty associated with derivatives trading; (ii) underpayment of royalty due to the improper deduction of transportation and fractionation fees; and (iii) underpayment of royalty associated with the “50- mile pricing prong.” [Docket No. 164]. At the conclusion of the day, the Court adjourned the trial to May 19, 2021 at 9:15 a.m. (prevailing Central time).
Day three of the trial began with the continued examination of Mr. Marshal. [Docket No. 165]. During Mr. Marshal’s cross-examination, it became apparent that Mr. Marshal had not conducted himself as an expert helpful to the Court. [Docket No. 165]. See FED. R. EVID. 702. To the contrary, Mr. Marshal acted as an advocate for Petty by making assumptions and taking positions in his royalty audit and testimony specifically intended to be favorable to Petty. [Docket No. 165]. The Court rejects Mr. Marshal’s purported opinions in their entirety as competent expert testimony1. While the Court generally accepts Mr. Marshal’s spreadsheets, the Court requires no assistance in Excel or basic math.
1 In footnote 28 of its brief, Petty requests that the Court reconsider its rejection of Mr. Marshall’s testimony based on the facts that Mr. Marshall (i) had historically reduced his calculations when presented with evidence of his mistakes; and (ii) had been stipulated to by the parties as a qualified expert. [Docket No. 171]. The Court grants the request. With the benefit of a complete review of the record, the Court affirms its prior decision. The Court specifically finds that Mr. Marshall (i) possesses no scientific, technical or other specialized knowledge that would assist the Court in performing its duties; (ii) failed to provide credible testimony that is the product of reliable principles and methods and (iii) failed to reliably After the conclusion of Mr. Marshal’s testimony, the Court read excerpts from the deposition of Stephanie Wade and heard testimony from Matthew Warren, Steven Armstrong and Patrick Herringer. [Docket No. 165]. The Court adjourned the trial to May 20, 2021 at 10:30 a.m. (prevailing Central time) after the conclusion of Mr. Herringer’s testimony.
Day four of the trial commenced with several evidentiary matters and then proceeded with the testimony of John Ellis and Kris Terry. [Docket No. 166]. Upon the conclusion of Ms. Terry’s testimony, the evidence was closed. [Docket No. 166]. Chesapeake then announced that it was in the process of filing a motion for judgment on partial findings pursuant to FED. R. CIV. P. 52(c). [Docket No. 166]. The Court adjourned the trial to May 21, 2021 at 10:30 a.m. (prevailing Central time) to allow sufficient time for the parties to prepare argument on the Rule 52(c) motion. [Docket No. 166]. After reviewing the Rule 52(c) motion, the Court postponed argument on the Rule 52(c) motion to closing arguments and utilized the May 21, 2021 hearing date to discuss a briefing scheduling and the timing for closing arguments. [Docket No. 162].
The Court heard closing arguments on May 28, 2021. [Docket No. 185]. At the conclusion of closing arguments, the Court took the matter under advisement. [Docket No. 174].
On July 1, 2021, the parties filed a “Joint Stipulation to Dismiss with Prejudice Certain of Petty’s Claims.” [Docket No. 187]. The stipulation contains the following language identifying the covered claims:
Specifically, the Settled Matters include the following claims asserted by Petty in their Amended Adversary Complaint, Adv. Proc. No. 20-03433 [Adv. Docket No. 44]: (a) the Debtors failed to pay royalties on 100% of produced oil, condensate, and liquid hydrocarbon volumes; (b) the Debtors failed to pay any royalties for skim oil volumes recovered from disposed saltwater produced with the minerals under the Leases; (c) the Debtors failed to pay on 100 percent of reported gas volumes; (d) the Debtors failed to properly account for the gas volumes used for gas lift purposes and thus failed to pay all royalties due on the net gas produced; and (e) the Debtors improperly deducted costs for gas processing. For the avoidance of doubt, the Settled Matters do not include (a) any claims or causes of action arising after June 30, 2020; (b) any claims or causes of action that have been asserted by Petty in the Adversary Proceeding or any related proofs of claim that are not Small Claims, as defined in the Settlement Agreement; and (c) any claims or causes of action for reasonable attorneys’ fees and expert expenses asserted in the Adversary Proceeding or any related proofs of claims that are not Small Claims, as defined in the Settlement Agreement.
[Docket No. 187].
apply the principles and methods to the facts of the case—all as required by FED. R. EVID. 702. The Court excludes as unreasonable all fees and costs of Mr. Marshall from the award of fees and costs approved below. Jurisdiction and Authority
The Court has jurisdiction over this adversary proceeding pursuant to 28 U.S.C. § 1334(b), (e) as this proceeding involves property of the estate. This adversary proceeding is a core proceeding under 28 U.S.C. §§ 157(b)(2)(A), (B), (E) and (O). The Court has constitutional authority to enter a final order in this contested matter. Stern v. Marshall, 564 U.S. 462, 486–87 (2011). To the extent necessary, the parties have impliedly consented to the entry of a final order by the Court. See Wellness Int’l Network, Ltd. v. Sharif, 135 S. Ct. 1932, 1947–48 (2015) (holding that a party impliedly consents to adjudication when the party “voluntarily appear[s] to try the case” with knowledge of the need for consent and without affirmatively refusing to provide it).
Analysis
The primary focus in this adversary proceeding is the proper calculation of royalty under the Leases and the amount, if any, owed by Chesapeake to Petty. In evaluating a claim for unpaid royalty, the Court must be guided by the terms of the parties’ mineral lease. Tittizer v. Union Gas Corp., 171 S.W.3d 857, 860 (Tex. 2005). The Court will address, in turn, each of Petty’s remaining claims.
NGL Claim
With continued improvements in drilling and recovery techniques, producers of oil and gas from shale formations are yielding increasing amounts of profitable natural gas liquids (“NGLs”). This mixture of raw products known as Y-grade consists of varying percentages of propane, ethane, isobutane, pentane and natural gasolines. To realize its inherent value, Y-grade must be separated into its various components or “fractionated.” The amounts of propane, ethane, etc. that are extracted are commonly known as purity products. The facilities that perform the fractionation process are highly specialized and primarily located along the Gulf Coast. The most notable of these locations is located in Mont Belvieu, Texas.
Petty negotiated for and received a royalty on these NGLs or Plant Products (as defined in the Leases) pursuant to a set of “greater of” pricing prongs. At issue in this case is the application of the following “gross proceeds prong:”
5. 2 PLANT PRODUCTS: Lessor's royalty on all products, except condensate, separated, extracted or manufactured from gas produced from the Leased Premises by an extraction, absorption, pressuring or other plant and not taken in kind (“Plant Products”) shall be calculated using the greater of:
(i) twenty-seven and one half percent (27½%) of the gross proceeds plus premium realized by Lessee or Lessee's related or affiliated entities from the sale of Plant Products to the first non-related or non-affiliated purchaser, or . . ..
[Docket No. 95-1]. As NGLs are produced by Chesapeake, they are forwarded in the gas stream to one of two processing plants where the dry gas or methane is removed, and the remaining Y-grade exists in a liquid form. At this point, title to the NGLs has passed to the processor pursuant to the terms of the relevant agreements.
The purchase price that Chesapeake receives is based upon an index price for each of the extracted purity products less a transportation and fractionation fee to convert the Y-grade to purity products (the “T&F Fee”). These fees are typically measured in cents per gallon consistent with industry standards. [Kris Terry, 5/20/21, Docket No. 166, pgs. 157-164]. An example of the calculations performed was admitted as Exhibit 100-8.
Under the Leases, the royalty due to Petty is free of any costs:
5. 9 FREE ROYALTY: Lessee agrees that all royalties accruing under this Lease shall be without any deduction whatsoever, either directly or indirectly, including but not limited to costs of producing, gathering, storing, separating, treating (except as otherwise provided for in Paragraph 5.3.2), dehydrating, compressing, processing, transporting (except as otherwise provided for in paragraph 5.3(ii) above) marketing and otherwise making Minerals produced hereunder ready for sale or use. . . . If any contract entered into by Lessee or used for determining value or price for royalty payments, as defined above, shall include any adjustment or reduction for any cost or expense, including the cost or expense of producing, gathering, dehydrating, compressing, transporting, manufacturing, processing, treating or marketing of Minerals, or if any such expenses are deducted by Lessee or the purchaser for purposes of arriving at a price or value for Minerals, then such adjustments or deductions shall be added to the value, price or proceeds realized for such Minerals, so that Lessor's royalty shall not be chargeable, directly or indirectly, with any of such allocations, costs or expenses, except such allocations, costs or expenses expressly permitted elsewhere in this Lease as an adjustment or deduction to Lessor's royalty.
[Docket No. 95-1] (emphasis added). The disputed issue in this adversary proceeding is whether the T&F Fee is a cost that must be added back to the price received by Chesapeake for purposes of calculating Petty’s royalty.
Chesapeake asserts that the T&F Fee is not an actual cost, but rather part of a pricing formula. In support of its position, Chesapeake argues that the T&F Fee is not based on the actual costs incurred by the purchaser. This argument misses the point. It is indisputable that that the T&F Fee is a “reduction for any cost or expense, including the cost or expense of producing, gathering, dehydrating, compressing, transporting, manufacturing, processing, treating or marketing of Minerals.” The fact that the reduction does not represent the purchaser’s actual cost is irrelevant and inserts language into Section 5.9 where none exists. See Devon Energy Prod. Co., L.P. v. Sheppard, 2020 WL 6164467, at *10-11 (Tex. App.—Corpus Christi Oct. 22, 2020, pet. filed). The unambiguous language of Section 5.9 of the Leases, while perhaps uncommon, reflects the parties’ agreement to include in the royalty base more than just the proceeds received by Chesapeake from the purchaser. See Id.; see also Yturria v. Kerr-McGee Oil & Gas Onshore, LLC, 291 FED. APP'X 626, 630 (5th Cir. 2008) (per curiam, not designated for publication).
The Court finds that the T&F Fee should have been added back to the royalty base prior to calculating Petty’s royalty on NGLs. From the briefing, it appears that the parties generally agree on the applicable computation required if the T&F Fee is added back to the royalty base although the precise calculation changed during the trial. The parties are instructed to confer regarding the specific amount of additional royalty due with the T&F Fee added back to the royalty base.
The Financial Derivative Claim
In the normal course of its business, Chesapeake uses a variety of financial transactions to hedge2 against downside commodity price volatility and provide stable cash flow. Petty asserts that it is entitled under the Leases to royalty on all gains realized by Chesapeake from these transactions. In support of its position, Petty relies on the following provision in the Leases:
5.7.2 Lessor is a third-party beneficiary of any agreement affecting the sale, exchange, use, disposition, marketing or transportation of Minerals under the Leased Premises . . .. Further, Lessor shall be entitled to twenty-seven and one half percent (27½ %) of any amount or benefits realized, recovered, derived, received, or obtained by or for the benefit of Lessee, or its affiliate or subsidiary, directly or indirectly, or granted to Lessee from any person or party, (i) for or emanating from the barter, contribution, disposition, settlement, exchange, sale, usage, hedging, buy-out or buy-back of Minerals (ii) under transportation agreements, purchase agreements, contracts, sales agreements, severance, any type of derivative agreement or swap of any one or more Minerals, (iii) for the execution, amendment, modification, extension, alteration, consolidation, transfer, cancellation, compromise or settlement of any agreement mentioned above, (iv) paid as a premium, commission, commitment, inducement, demand fee, load management fee or fee of similar import in order to commit Minerals to such buyer or dealer, or (v) as an inducement to sell Minerals or in settlement thereof or any right, obligation or claim. . . . It is the intent of Lessor and Lessee that Lessee pay royalty on each and every benefit received by Lessee while marketing production as the result of each and every arrangement between Lessee and any third party emanating from the value of hydrocarbons produced from the Leased Premises.
[Docket No. 95-1] (emphasis added). Minerals are defined as “a fee simple determinable interest in oil, gas, and all other hydrocarbons and sulphur necessarily produced with oil or gas, from the Leased Premises.” [Docket No. 95-1].
Chesapeake asserts that the foregoing provision is not applicable to its financial management activities as no Minerals were ever specifically hedged or the subject of any type of
2 While accomplished through a variety of complex financial vehicles such as futures, swaps, puts and collars, a hedge in simple terms is an investment made for the purpose of reducing the risk of adverse price fluctuations in an underlying asset. For an oil and gas producer such as Chesapeake, the underlying asset is the oil and gas produced from its operating wells. derivative agreement. While acknowledging that no Minerals were never the subject of any hedging transaction, Petty asserts that because (i) Chesapeake routinely hedged substantially all of its production; (ii) Chesapeake’s loan documents prohibited uncovered commodity speculation; and (iii) the very existence of the Minerals enabled Chesapeake’s hedging program to occur, it is entitled to a royalty on all hedging gains realized by Chesapeake.
The Court has previously stated that the parties’ chosen words in an agreement matter and evidence their true intent. In re Chesapeake Energy Corp., 622 B.R. 274, 284 (Bankr. S.D. Tex. 2021); see also Tittizer v. Union Gas Corp., 171 S.W.3d 857, 860 (Tex. 2005) (per curiam) (stating that courts should construe a mineral lease so as to enforce the expressed intention of the parties). Each of the relevant provisions of Section 5.7.2 of the Leases require the involvement of Minerals—actual production from the Leases. The record adduced in this proceeding reflects no allocation by Chesapeake of Minerals, no designation by Chesapeake of production from the Leases, no pledge by Chesapeake of Minerals. In short, no evidence exists that any Minerals were ever at risk in any hedging transaction undertaken by Chesapeake. See In re Ultra Petroleum Corp., 571 B.R 755, 764 (Bankr. S.D. Tex. 2017). The Court concludes that no royalty is due on gains from Chesapeake’s financial hedging program. Petty’s Financial Derivative Claim is denied.
50-Mile Oil/Condensate Pricing Claim
Under the Leases, Petty is entitled to a royalty on all oil, condensate and field liquids produced by Chesapeake. Petty’s royalty is again calculated using a set of “greater of” pricing prongs. At issue is the following prong:
5.1 . . . Lessor's royalty shall be calculated using the greater of:
(iv) twenty-seven and one half percent (27½%) times the Liquid Volume times the greater of the highest price that (a) Lessee or (b) any co-lessee in this Lease or (c) any cotenant in the Leased Premises, receives or realizes during the same production month from the sale, trade or any other disposition of oil and/or liquid hydrocarbons produced from or within Fifty miles (50) of the Leased Premises, subject to adjustments for any differences in quality or gravity.
[Docket No. 95-1]. Petty asserts that Chesapeake incorrectly calculated the amount of royalty due by (i) using the amount paid at the well to Chesapeake Operating by Chesapeake Energy Marketing and not the resale price to a third party; and (ii) inappropriately applying gravity adjustments to production from Petty wells.
Section 5.1(iv) of the Leases specifies that royalty is to be calculated on the highest price received by the Lessee3 during the production month from any well within 50 miles of the Leases. [Docket No. 95-1]. Petty argues that the appropriate measure is the highest price received by any Chesapeake affiliate from any well within 50 miles of the Leases. Although not contained in
3 The actual language specifies the highest price received by “(a) Lessee or (b) any co-lessee in this Lease or (c) any cotenant in the Leased Premises.” The parties do not dispute that “Lessee” is the appropriate focus under the circumstances presented. Likewise, no suggestion was made that the price paid by Chesapeake Energy Marketing was below market. Section 5.1(iv), this concept was incorporated into Section 5.1(i) as well as other royalty-related provisions of the Leases. The Court will interpret the Leases in a manner that recognizes the benefits and burdens bestowed under each provision. See Heritage Resources Inc., v. NationsBank, 939 S.W.2d 118, 121 (Tex. 1996). The Court will not insert words into Section 5.1(iv) that do not exist. See In re Davenport, 522 S.W. 3d 452, 457 (Tex. 2017). Petty further refers to the language of Section 5.3(i) stating that sales to affiliates should be ignored. This reference actually bolsters Chesapeake’s position. Section 5.3 addresses royalty due on produced gas and specifically references amounts received by “Lessee or Lessee’s related entities, affiliates and/or subsidiaries” from the first non-affiliated purchaser. In the absence of any evidence of fraud or price manipulation, the Court finds that the price received by the Lessee regardless of whether the purchaser is an affiliate is the proper point for measurement of Petty’s royalty under this prong of the royalty calculation.
Petty further argues that because Chesapeake combined the production from the Leases with other non-Petty production to achieve a blended gravity for downstream purchasers, no price adjustments for gravity were required. It was undisputed at trial that the production from the Leases has a lower API gravity and is of poorer quality than production from wells in the surrounding 50 miles. [Matt Warren, 5/19/21, Docket No. 165, pgs. 80-82; Jon Ellis, 5/20/21, Docket No. 166, pgs. 21–34]. Without a proper adjustment for gravity and stabilization, Petty would inappropriately realize the increased value of production from the Leases being blended with more desirable production with no attendant costs. Petty bore the burden to prove that Chesapeake’s adjustments were unreasonable. Petty failed to prove that Chesapeake’s adjustments for gravity and quality were improper. The 50-Mile Oil/Condensate Pricing Claim is denied except to the extent that the parties agree that due to the Court’s prior rulings, an additional royalty of $314 is owed.
To the extent that the Court has determined above that Chesapeake owes unpaid royalty to Petty, the Court finds that Chesapeake is liable for such nonpayment under the Texas Natural Resources Code. Such amounts will be paid in accordance with the Plan.
Breach of Duty of Utmost Good Faith and Fair Dealing
In its amended complaint, Petty asserts that Chesapeake breached its contractual duty of good faith and fair dealing in three material ways. [Docket No. 44]. First, Petty asserts that Chesapeake violated its duty by incorrectly calculating Petty’s share of severance taxes. [Docket No. 44]. Second, Petty asserts that Chesapeake modified several of its pad facilities to circumvent the recovery of flash gas. [Docket No. 44]. Finally, Petty asserts that Chesapeake acted in bad faith in the production of information needed for Petty to conduct its royalty audits. [Docket No. 44]. The Leases contain the following language:
iii. The standard of conduct or duty that Lessee owes to Lessor and each royalty owner in managing this Lease and performing the express and implied duties and obligations imposed on Lessee under the terms of this Lease shall be utmost good faith and fair dealing, except, however, as to Paragraph 5.7, Lessee's standard of conduct or duty to Lessor and each royalty owner shall be the same duty that a trustee owes to a beneficiary. However, any breach of Lessee's standard of conduct under Paragraph 5.7 shall never subject Lessee to punitive or compensatory damages.
[Docket No. 95-1] (emphasis added). In the mineral lease context, Texas courts have construed this duty to require that the mineral owner avoid any form of self-dealing or intentionally obtaining a disproportionate benefit to the detriment of the nonpossessory royalty owner. See Manges v. Guerra, 673 S.W.2d 180 (Tex.1984); Mims v. Beall, 810 S.W.2d 876 (Tex. App.—Texarkana 1991, no writ); Pickens v. Hope, 764 S.W.2d 256 (Tex. App.—San Antonio 1988, writ denied). In 2003, the Texas Supreme Court in In re Bass determined that a duty of utmost good faith and fair dealing required a grantee, after executing a mineral lease, to protect the grantor’s royalty. 113 S.W. 735, 744 (Tex. 2003).
The payment of royalty owed to Petty under the Leases is governed by the following provision:
5.10 ROYALTY PAYMENTS:
5.10.1 Except for any reasonable delay at the inception of production from a well on the Leased Premises occasioned by delay in Lessee or the purchaser of the production being furnished with and examining abstracts of title, Lessee WARRANTS that all royalties which are required to be paid hereunder shall be due and payable no later than the last day of the second month after the end of the month of production of Minerals.
[Docket No. 95-1].
As noted above, the Court granted summary judgment in Petty’s favor on the improper deduction of severance taxes and in Chesapeake’s favor on the flash gas claim [Docket No. 94]. With respect to the severance tax claim, however, an error in contract interpretation is a far cry from an intentional breach of duty. See KCM Financial LLC v. Bradshaw, 457 S.W.3d 70, 81 (Tex. 2015) (equating a breach of duty owed to royalty owner with self-dealing). Petty failed to adduce any evidence to support its claim for a breach of duty with respect to the severance taxes or flash gas. In post-trial briefing, Petty focused its argument in support of its claim on the following exchange between the Court and Steve Armstrong, a revenue accounting supervisor for Chesapeake: THE COURT: Mr. Armstrong, you testified on direct that, with respect to the 50- mile calculation, that it's very difficult for you to do and that you don't do it on a periodic basis. Did I understand you correctly?
THE WITNESS: That is correct, sir.
THE COURT: When do you do it?
THE WITNESS: We normally do that as to when an audit is conducted.
THE COURT: So you just wait.
THE WITNESS: Yes, sir
[Steven Armstrong, 5/19/21, Docket No. 165, pgs. 124:12–21]. The following passage provides additional context to the Court’s questions and Mr. Armstrong’s responses:
Q Is the 50-mile calculation something that Chesapeake Operating does from month to month in real time to pay Petty royalties?
A No, it's not.
Q I'm going to take you back in time, Mr. Armstrong. Have you discussed in the past with Pettys' auditors that there are difficulties in preparing this form of document in real time?
A Yes, I have.
Q And who did you have that discussion with?
A I believe I've had that discussion in the past with Mr. Bill Waterman, as well as with Mr. Dave Marshall.
Q Did Mr. Waterman tell you that it was acceptable for Chesapeake to do this analysis on a look-back basis?
A As I recall today, yes.
[Steven Armstrong, 5/19/21, Docket No. 165, pgs. 110:2–15]. Mr. Armstrong went on to testify that once the calculation was done in November 2020, the amount of additional royalty due to Petty for the 2016-2020 period was approximately $314. [Steven Armstrong, 5/19/21, Docket No. 165, pg. 111:2]. Mr. Armstrong further testified that the continuous audit process between Petty and Chesapeake was in the normal course of the parties’ relationship. [Steven Armstrong, 5/19/21, Docket No. 165, pgs. 124:3-126:3]. The Court finds this arrangement troubling and indicative of future disputes. The Court will accept at face value Chesapeake’s undertaking to change its conduct regardless of Petty’s acquiescence. Notwithstanding its expressed concern, the Court finds that the evidence adduced in this adversary proceeding does not support a claim for the breach of an utmost duty of good faith and fair dealing. Petty’s claim is denied.
Breach of Fiduciary Duty
Under the Leases, Chesapeake owes the following duty to Petty:
Lessee's standard of conduct or duty to Lessor and each royalty owner shall be the same duty that a trustee owes to a beneficiary. However, any breach of Lessee's standard of conduct under Paragraph 5. 7 shall never subject Lessee to punitive or compensatory damages.
[Docket No. 95-1, Definitions and Standard of Conduct, iii]. In its amended complaint, Petty asserts that Chesapeake breached this duty by failing to pay Petty royalty on gains from its financial hedging activities. [Docket No. 44]. Petty asserts that Chesapeake’s repeated failure to properly calculate other royalty due also breached this duty. [Docket No. 44]. Finally, in its post-trial brief, Petty asserts that Chesapeake’s failure to timely answer discovery breached this duty. [Docket No. 171].
Petty’s claim fails for several reasons. First, the Court has determined that no royalty is due on Chesapeake’s financial hedging activities. Second, Petty failed to prove that any royalty error by Chesapeake in calculating Petty’s royalty was anything other than a mistake. Third, any damage relevant to hedging would necessarily be limited to the amount due under Section 5.7.2 of the contract given the above damage limitation. Finally, any issues that arose in discovery would fall under the purview of FED. R. CIV. P. 37. Petty’s claim for breach of fiduciary duty is denied.
Interest
The Leases provide the following with respect to the entitlement to interest on unpaid royalty:
5.10.1 … Any royalty not paid within the time specified herein shall be deemed delinquent and shall bear interest at the highest rate allowed by law applicable to this transaction, but in no event less than ten (10%) percent per annum.
[Docket No. 95-2]. The Leases further provide instruction on the accrual of interest on other amounts owed:
26. REIMBURSEMENT: In the event Lessor or any royalty owner is owed any sums of money accruing under this Lease or in the event Lessor and/or any royalty owner hereunder shall institute proceedings, including but not limited to resorting to a court of law or to Alternative Dispute Resolution provided for in Paragraph 28.1 of this Lease, to enforce or interpret any provision, covenant, condition, duty, obligation or commitment, whether expressed or implied, arising out of this Lease, then Lessee shall pay Lessor or any royalty owner, as the case may be, the sums owed plus interest thereon at the rate provided for in Paragraph 5.10 above. Further, Lessee shall reimburse the party entitled thereto for all damages, losses, costs, fees and expenses, including reasonable attorney's fees, accountant's fees, engineer's fees, consultant's fees and/or expert's fees, incurred in such regard, regardless whether incurred before or after bringing proceedings.
[Docket No. 95-2].
Petty asserts that the reference to “highest amount allowed by law” refers to the Texas Finance Code and that such amount is currently 18%. [Docket No. 86-1]. Under § 303.001 of the Texas Finance Code,
a person may contract for, charge, or receive a rate or amount that does not exceed the applicable interest rate ceiling provided by this chapter. The use of a ceiling provided by this chapter for any contract is optional, and a contract may provide for a rate or amount allowed by other applicable law.
TEX. FIN. CODE § 303.001. Section 303.009 provides that “[i]f the rate computed for the weekly, monthly, quarterly, or annualized ceiling is less than 18 percent a year, the ceiling is 18 percent a year.” TEX. FIN. CODE § 303.009(a). The current calculated rate is available online from the Texas Office of Consumer Credit Commissioner at https://occc.texas.gov/publications/interest-rates. The parties do not dispute that the current applicable ceiling is 18% per annum.
Chesapeake asserts, however, that because the issue in controversy is the alleged nonpayment of royalty, the provisions of the Texas Natural Resources Code control. [Docket No. 86-1]. Section § 91.403 of the Texas Natural Resources Code provides, in relevant part, that
[i]f payment has not been made for any reason in the time limits specified in Section 91.402 of this code, the payor must pay interest to a payee beginning at the expiration of those time limits at two percentage points above the percentage rate charged on loans to depository institutions by the New York Federal Reserve Bank, unless a different rate of interest is specified in a written agreement between payor and payee.
TEX. NAT. RES. CODE § 91.403(a) (emphasis added). The parties do not dispute that if the Texas Natural Resources Code controls, the floor rate of ten percent per annum set forth in Section 5.10 of the Leases would control.
Petty asserts that this question was answered in Samson Exploration v. T.S. Reed Properties, 521 S.W.3d 26, 55–56 (Tex. App.—Beaumont 2015), aff’d, 521 S.W.3d 766 (Tex. 2017). In Samson, the parties agreed to the payment of interest at “the prime rate of interest at Chase–Manhattan Bank in New York City, New York, plus 2% (not to exceed legal Texas interest rate).” 521 S.W.3d at 55. In holding that the words “not to exceed” implicitly referenced the Texas Finance Code and not the Texas Natural Resources Code, the Samson court based its decision on the parties’ specification of a different interest rate. Id.
Chesapeake counters Petty’s arguments by (i) referencing other provisions in related documents that specifically refer to “the maximum contract rate permitted by the applicable usury laws in the state in which the Joint Property is located”; and (ii) noting that with the current limits under the Texas Finance Code, the ten percent floor could never occur thereby rendering the language meaningless. [Docket No. 87]. While the Court agrees that when engaging in contract interpretation, the Court should attempt to give effect to all provisions of an agreement, the Court believes the above arguments miss a salient point.
Reviewing the plain language of Section 91.403 of the Texas Natural Resources Code, the Court finds that the section operates to specify a default rate in applicable situations if the parties have not otherwise agreed in writing to either (i) the payment of interest; or (ii) a specific interest rate. TEX. NAT. RES. CODE § 91.403(a); see also Samson, 521 S.W.3d at 55. The pertinent question that the Court must answer is whether the language, “the highest rate allowed by law applicable to this transaction, but in no event less than ten (10%) percent per annum” specifies an interest rate. The Court finds that it does.
The Court is not persuaded by Chesapeake’s alternative arguments. With respect to the argument that the ten percent prong of Section 5.10.1 could never occur, one only need to examine the entirety of the Texas Finance Code to get clarity. Effective September 1, 2001, Section 302.001 of the Texas Finance Code provided that the maximum rate of interest in Texas is ten percent per annum unless otherwise provided by law. TEX. FIN. CODE § 302.001(b). While the rate ceiling exceptions created in Section 303 effectively render the base rule a nullity, the ten percent prong in section 5.10.1 of the leases functions to set the minimum interest rate at the base maximum rate of interest specified in Section 302.001. See Leteff v. Roberts, 555 S.W.3d 133, 137 (Tex. App.— Houston [1st Dist.] 2018, no writ). The highest rate allowed by law recognizes the applicable rate ceiling established in Section 303.001. Should the parties desired to have opted out of Section 303, they could have easily done so. See TEX. FIN. CODE § 303.001(a).
The Court agrees with Chesapeake that other related documents make specific reference to all states’ usury laws. Contrary to Chesapeake’s assertions, however, this argument supports Petty’s position. The joint operating agreement referenced by Chesapeake is applicable in multiple states and applies the usury law of the governing state. The Leases are governed solely by Texas law. Under Petty’s theory, all of the related agreements are controlled by the applicable usury statutes of the governing state’s law and are consistent in their approach. The Court finds that the applicable pre-judgment interest rate is 18%. Pursuant to 28 U.S.C. § 1961, the proper post- judgment interest rate is the federal post-judgment rate which is calculated by taking the weekly average 1-year constant maturity (nominal) Treasury yield, as published by the Federal Reserve System each Monday for the preceding week (unless that day is a holiday in which case the rate is published on the next business day). The current Federal post-judgment rate is .07%. Attorney’s Fees Under the Leases, Petty is entitled to the following remedy in the event of an underpayment of royalty: 26. REIMBURSEMENT: In the event Lessor or any royalty owner is owed any sums of money accruing under this Lease or in the event Lessor and/or any royalty owner hereunder shall institute proceedings, including but not limited to resorting to a court of law or to Alternative Dispute Resolution provided for in Paragraph 28.1 of this Lease, to enforce or interpret any provision, covenant, condition, duty, obligation or commitment, whether expressed or implied, arising out of this Lease, then Lessee shall pay Lessor or any royalty owner, as the case may be, the sums owed plus interest thereon at the rate provided for in Paragraph 5.10 above. Further, Lessee shall reimburse the party entitled thereto for all damages, losses, costs, fees and expenses, including reasonable attorney's fees, accountant's fees, engineer's fees, consultant's fees and/or expert's fees, incurred in such regard, regardless whether incurred before or after bringing proceedings. [Docket No. 95-1] (emphasis added). Based on the above, the Court finds that Petty is entitled to its reasonable fees and costs. In accordance with the stipulation of the parties, the appropriate amount of the fees and costs to be awarded will be determined “by motion practice in accordance with FED. R. Civ. P. 54({d]) [sic].” [Docket No. 133]. Further Proceedings In accordance with the stipulations of the parties, the Court directs the parties to (i) initiate the procedure for the calculation and award of attorney’s fees and costs as set forth above; (11) calculate the amount of royalty owed under the controlling provision of the NGL Claim; (iii) confer regarding the calculation of pre-judgment interest; (iv) prepare and submit a proposed judgment implementing the Court’s rulings; and (v) prepare and submit a proposed order directing payment from the reserved amounts in the main bankruptcy proceeding in accordance with the confirmed Plan. Should the parties be unable to reach an agreement on the applicable calculations, the parties should jointly contact the Court’s case manager and obtain a hearing date to resolve any outstanding issues. All other relief is denied. SIGNED: September 14, 2021.
DAVID R. JONES UNITED STATES BANKRUPTCY JUDGE
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