Oil & Gas Law Chapter 7: Royalty Clauses and Division Orders Professors Wells

Presentation:

October 30, 2017

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Royalty Clauses: Southland Royalty Co. v. Pan American Corp.

Southland Royalty Co. v. Pan American Corp, 378 S.W.2d 50: 1.  Facts

1st To deliver to the credit of lessor, free of cost, in the pipe line to which they may connect their wells, the equal one-eighth part of all oil produced and saved from the leased premises and 1/8 of the net proceeds of potash and other minerals at the mine.

2nd To pay the lessor One Hundred Dollars, each year in advance for the gas from each well where gas only is found, while the same is being used off the premises, and lessor to have gas free of cost from any such well for all stoves and all inside lights in the principal dwelling house on said land during the time by making their own connections with the well at their own risk and expense.

3rd To pay lessor for gas produced from any oil well and used off the premises at the rate of Fifty and No/100 Dollars per year for the time during which such gas shall be used, said payments to be made each three months in advance.

2.  Court reasoning

“We also think there is no serious question raised but that the words “mineral” or “minerals” include gas.”

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Model Lease Agreement: Bifurcated Royalty & Free Use of Gas

Paragraph 3 The royalties to be paid by Lessee are: . . . (b) on gas, including casinghead gas or other gaseous substance, produced from said land and sold or used off the premises or for the extraction of gasoline or other product therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the amount realized from such sale. * * * * Lessee shall have free use of oil, gas, coal, and water from said land, except water from Lessor’s wells, for all operations hereunder, and the royalty on oil, gas, and coal shall be computed after deducting any so used.

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Royalty Clauses: Cannon v. Cassidy

Cannon v. Cassidy, 542 P.2d 514: 1.  Facts

2.  Court reasoning

“[L]essee’s failure to pay royalty as provided by the lease will not give lessors sufficient grounds to declare a forfeiture unless by the express terms of that lease they are given that right and power. We note in passing that the overwhelming majority of jurisdictions which have considered this issue are in accord.”

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Royalty Clauses: Model Lease Agreement

Paragraph 9 The breach by Lessee of any obligation arising hereunder shall not work a forfeiture or termination of this lease nor cause a termination or reversion of the estate created hereby nor be grounds for cancellation hereof in whole or in part. In the event Lessor considers that operations are not at any time being conducted in compliance with this lease, Lessor shall notify Lessee in writing of the facts relied upon as constituting a breach hereof, and Lessee, if in default, shall have sixty (60) days after receipt of such notice in which to commence the compliance with the obligations imposed by virtue of this instrument. After the discovery of oil, gas or other mineral in paying quantities on said premises, Lessee shall develop acreage retained hereunder as a reasonable prudent operator but in discharging this obligation it shall in no event be required to drill more than one well per forty (40) acres of the area retained hereunder and capable of producing oil in paying quantities and one well per 640 acres plus an acreage tolerance not to exceed 10% of 640 acres of area retained hereunder incapable of producing gas or other mineral in paying quantities.”

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Royalty is a fractional share of production or revenues received from selling the production. Example: Royalty = 1/8th of oil and gas produced and sold. Here, royalty = 1/8th of price x quantity

•  By the contract price received for the gas sold from the lessor’s tract? •  By the market value of similar oil or gas, sold by others? •  By an index price (that is used to measure the market value at a hub)? •  In kind?

•  “At the well”? •  At the point of sale to an affiliate? •  At the point of sale to the first non-affiliated, third party buyer? •  At the point of delivery to [what facility– a pipeline, a processing plant, a market hub]? •  At the tailgate of a gas processing plant?

•  Gas from a well only? •  Casinghead gas from an oil well? •  Oil? •  Carbon dioxide and other gases? Sulfur?

•  When produced? •  When produced and sold? Produced and sold and delivered? •  When is the gas sold? It the gas sold under a long-term contract is signed to sell the gas at a fixed price?

•  E.g., under a “proceeds” or “amount realized” lease? •  Under a “market value” lease?

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Royalty Clauses: Market Value vs. Proceeds Texas Oil and Gas Corp. v. Vela

Texas Oil and Gas Corp. v. Vela, 429 S.W.2d 866: 1.  Facts

“pay to lessor, as royalty for gas from each well where gas only is found, while the same is being sold or used off of the premises, one-eighth of the market price at the wells of the amount so sold or used”

2.  Court reasoning

“Instead of doing so, however, they stipulated in plain terms that the lessee would pay one-eighth of the market price at the well of all gas sold or used off the premises. This clearly means the prevailing market price at the time of the sale or use. The gas which was marketed under the long-term contracts in this case was not “being sold” at the time the contracts were made but at the time of the deliver to the purchase. We agree with the Court of Civil appeals, therefore, that the contract price for which the gas was sold by the lessee is not necessarily the market price within the meaning of the lease.”

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Royalty Clauses: Market Value vs. Proceeds Exxon Corp. v. Middleton

Exxon Corp. v. Middleton, 613 S.W.2d 240: 1.  Facts

2.  Court reasoning

“Market value may be calculated by using comparable sales. Comparable sales of gas are those comparable in time, quality, quantity, and availability of marketing outlets. ** * Sun argues the trial court correctly held, under well-settled law that these instruments [division orders] were binding for the time the parties acted under them. We agree.”

Anuhuac Field Annuhuac Main Gas Unit #1

Middleton

Middleton

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Royalty Clauses: Market Value vs. Proceeds Problem Set on page 7-22

Problem Lessor Able and Lessor Baker have leased adjacent tracts to Bigg Oil. Bigg has erected a processing plan on Able’s tract. Both leases have the typical bifurcated royalty clause: “proceeds” royalties are paid on sales at the well and “market value at the well” royalties are paid for sales off the lease. The lessee sells all the gas from both Able’s and Baker’s tracts at the tailgate of the processing plant for $2.20 per MCF. Processing costs amount to 20 cents per MCF. (A) What price is used to value Able’s royalty?

Answer: Bigg Oil has the plant on Able’s lease and sells the gas from Able’s land, so the proceeds from the plant are the proceeds from the wells on the lease, and so Able should be 1/8th of $2.20.

(B) What price is used to value Baker’s royalty?

Answer: Baker’s gas is sold off the lease, so Baker will get 1/8th of whatever the market value at the well is determined to be, minus 20 cents. Baker’s royalty will be subject to deductions for post-production costs, unlike Able’s royalty, but it will be based on current market value of gas regardless of gross proceeds from the sale of the gas.

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Royalty Clauses: Market Value vs. Proceeds Piney Woods Country Life School v. Shell Oil Co.

Piney Woods Country Life School v. Shell Oil Co., 726 F.2d 225: 1.  Facts

2.  Court reasoning

“We conclude that the purpose is to distinguish between gas sold in the form in which it emerges from the well, and gas to which value is added by transportation away from the well or by processing after the gas is produced. The royalty compensates the lessor for the value of the gas at the well; that is, the value of the gas after the lessee fulfills its obligation under the lease to produce gas at the surface, but before the lessee adds to the value of this gas by processing or transporting it. When the gas is sold at the well, the parties to the lease accept a good-faith sale price as the measure of the value at the well. But when the gas is sold for a price that reflects value added to the gas after production, the sale price will not necessarily reflect the market value of the gas at the well. Accordingly, the lease bases the royalty for this gas not on actual proceeds but on market value.

“At the well” therefore describes not only location but quality as well. Market value at the well means market value before processing and transportation, and gas is sold at the well if the price paid is consideraton for the gas as produced but not for processing and transportation.”

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Royalty Clauses: Market Value vs. Proceeds Yzaguirre v. KCS Resources, Inc.

Yzaguirre v. KCS Resources, Inc., 53 S.W.3d 368: 1.  Facts

2.  Court reasoning

“Because the lease provides an objective basis for calculating royalties that is independent of the price the lessee actually obtains, the lessor does not need the protection of an implied covenant. * * * Market value is the prevailing market price at the time of delivery and is not affected by a price set at the time the lessee enters into a long-term sales contract with the buyer.”

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Royalty Clauses: Market Value vs. Proceeds Heritage Resources, Inc. v. Nationsbank

Heritage Resources, Inc. v. Nationsbank, 939 S.W.2d 118: 1.  Facts

(b) on gas . . . sold or used off the premises or in the manufacture of gasoline or other products therefrom, the market value at the well of 1/5 of the gas so sold or used, provided, however, that there shall be no deductions from the value of the Lessor’s royalty by reason of any required processing, cost of dehydration, compression, transportation or other matter to market such gas.

2.  Court reasoning

“We recognize that our construction of the royalty clauses in two of the three leases arguably renders the post-productions clause unnecessary where gas sales occur off the lease. However, the commonly accepted meaning of the "royalty" and "market value at the well" terms renders the post-production clause in each lease surplusage as a matter of law..”

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•  Gas is sold produced when it is extracted from the ground •  Gas is sold when it is delivered •  Gas is delivered, sold, and produced at the same time in one continuous flow

•  Market Value equals market price at the time of sale/production/delivery •  So, market value long term contract price; gas is not sold when long-term

contract is signed. Much of the gas can be stored for years.

•  Both Prongs allow lessee to deduct post-production costs because of “at the well.”

•  “To determine market value, gas should be valued as though it were free and available for sale. Market value is the prevailing market price at the time of delivery and is not affected by a price set at the time the lessee enters into a long-term sales contact with buyer.”

Oil & Gas

Lease

Gas

Sales Contract

Royalty Clause in lease says: Sold or Used Off Lease

Sold “At the Well”

“On the Premises”

1/8th of Market Value at the Well Does the intercompany price represent the best possible price? (Yzaguirre)

1/8th of Amount Realized (proceeds) Does the intercompany price represent market? (Amoco v. First Baptist Church)

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Royalty Clauses: “Market Value At the Well” Chesapeake v. Hyder

Chesapeake v. Hyder, 427 S.W.3d 472: 1.  Facts

Lessee covenants and agrees to pay Lessor the following royalty: (a) twenty-five percent (25%) of the market value at the well of all oil and other liquid hydrocarbons produced and saved from the Leased Premises as of the day it is produced and stored; and (b) for natural gas, including casinghead gas and other gaseous substances produced from the Leased Premises and sold or used on or off the Leased Premises, twenty-five percent (25%) of the price actually received [note: not Market Value at the Well] by [appellants] for such gas .... The royalty reserved herein by [appellees] shall be free and clear of all production and post-production costs and expenses, including but not limited to, production, gathering, separating, storing, dehydrating, compressing, transporting, processing, treating, marketing, delivering, or any other costs and expenses incurred between the wellhead and [appellant’s] point of delivery or sale of such share to a third party. In no event shall the volume of gas used to calculate Lessors' royalty be reduced for gas used by Lessee as fuel for lease operations or for compression or dehydration of gas. ... Lessors and Lessee agree that the holding in the case of Heritage Resources, Inc. v. Nationsbank, 939 S.W.2d 118 (Tex. 1996) shall have no application to the terms and provision of this Lease.

2.  Court reasoning The parties modified the general rule by agreement, and we interpret the parties’ agreement as the royalty clause excluding all costs and expenses of production and post-production, including post-production costs and expenses incurred between the point of delivery and the point of sale. Our conclusion is reinforced by the parties’ agreement that the holding in Heritage—that the measure of the “value of the Lessor’s royalty” required a deduction for post-production costs, and therefore, the leases’

“no deduct” provision was “surplusage as a matter of law”—did not apply to the terms and provisions of the Hyder lease.

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Royalty Clauses: “Market Value At the Well” Chesapeake v. Hyder

Customer #1

Chesapeake Operating, Inc. (“COI”)

Lessee/Operator

Sells gas

“at the wellhead” Chesapeake Energy

Manufacturing (“CEMI”)

Distributor/Marketer

Gathering Lines

Interstate Pipeline

Sells gas at

Various delivery points (WASP=$3.30)

Central Hub

Customer #2

Customer #3

80 mcf @$3

10 mcf @$4

Wellhead

Chesapeake Midstream Partners, L.P. (“CMP”)

Gas Handler

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Royalty Clauses: Chesapeake v. Hyder Overriding Royalty Clause

The overriding royalty clause provided as follows: “a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent (5.0%) of gross production obtained”

5-4 decision stating that post-production costs could not be used to reduce the royalty obligation. Which opinion (majority or dissent) do you think is better? Could the lease have been better drafted?

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Royalty Clauses: “Market Value At the Well” Hyder Review Problem #1

The royalty clause in a Texas lease states that Lessee is to pay royalties equal to: "20% of the amount realized by Lessee, computed at the mouth of the well.” The lease also contains an addendum, as follows: Lease addendum: Notwithstanding anything to the contrary, herein contained, all royalty paid to Lessor shall be free of all costs and expenses related to the exploration, production and marketing of oil and gas production from the lease including, but not limited to, costs of compression, dehydration, treatment and transportation. Lessor will, however, bear a proportionate part of all those expenses imposed upon Lessee by its gas sale contract to the extent incurred subsequent to those that are obligations of Lessee. It is expressly agreed that the provisions of this Exhibit shall super[s]ede any portion of the printed form of this Lease which is inconsistent herewith, and all other printed provisions of this Lease, to which this is attached, are in all other things subrogated to the express and implied terms and conditions of this Addendum. 1.  What result for Lessor? 2.  Where is point of valuation? 3.  Would you answer change if the lease also contained Hyder’s “anti-Heritage” language?

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Royalty Clauses: “Market Value At the Well” Hyder Review Problem #2 (2nd Lease in Warren v. Chesapeake, 759 F.3d 413 (5th Cir. 2014))

Suppose the lease provision included the same royalty provision of 20% of the "amount realized at the mouth of the well." An Exhibit attached to the lease provided: "Notwithstanding any of the provisions of the lease, royalties are to be calculated as the market value at the point of sale of 20% of the gas so sold. Notwithstanding anything to the contrary herein, all royalty paid to Lessor shall be free of all costs and expenses related to the exploration, production and marketing of oil and gas production from the lease including, but not limited to, costs of compression, dehydration, treatment and transportation.” What result for Lessor?

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Royalty Clauses: “Market Value At the Well” Hyder Review Problem #3 (Potts v. Chesapeake, 760 F.3d 470 (5th Cir. 2014))

Suppose the royalty clause states as follows:

"Royalties to be paid by Lessee are: . . . on gas, the market value at the point of sale of 1/4 of the gas sold. . . .Notwithstanding anything to the contrary herein, all royalty paid to Lessor shall be free of all costs and expenses related to the exploration, production and marketing of oil and gas production from the lease including, but not limited to, costs of compression, dehydration, treatment and transportation.”

"Payments of royalties to Lessor shall be made monthly and shall be based on sales of oil and gas to unrelated third parties at prices arrived at through arms length negotiations. Royalties to Lessor on oil and gas not sold in an arms length transaction shall be determined based on prevailing market values at the time in the area. Lessee shall have the obligation to disclose to Lessor any information pertinent to this determination.”

Chesapeake Operating, Inc. (COI) sells the gas produced from the lease to Chesapeake Energy Marketing, Inc. (CEMI) at the wellhead. CEMI transports the gas through a gathering system, sends it through interstate pipelines, and resells it to various unaffiliated purchasers. CEMI pays Chesapeake Exploration and COI the weighted average sales price (WASP) that CEMI receives from these third-party purchasers, after deducting post-production costs incurred between the wellhead and the sales points to third-party purchasers. Chesapeake Exploration pays Lessor 1/4 of the price received from CEMI. In other words, Chesapeake, as Lessee, accounts for royalties using a "netback" value: Gross revenues received from third-party purchasers, minus costs incurred from the wellhead to the sales point where the third-party took title to the gas.

Lessors claim that the deductions are not allowed under the lease terms. Are they?

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Royalty Clauses: Implied Covenant to Market Amoco Production Co. v. First Baptist Church of Pyote

Amoco Production Co. v. First Baptist Church of Pyote, 579 S.W.2d 280: 1.  Facts

2.  Court reasoning

“In this case, Amoco by dedicating additional leases, including those of the Appellees herein, in June, 1975, obtained an increased price for gas already dedicated under the prior contract from 17 to 70 cents per MCF. This was obviously a substantial benefit for Amoco and its royalty owners under the previously dedicated leases. But it also meant that as to twelve of the leases involved in this case, the royalty owners would receive a payment for gas which was approximately ½ of the amount soon to be paid by Lone Star and Delhi, and with a very limited provision for future acceleration. This was not a substantial benefit to them as compared to other royalty owners whose gas was soon to be purchased by Lone Star and Delhi.”

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Royalty Clauses: Implied Covenant to Market Cook v. Tompkins

Cook v. Tompkins, 713 S.W.2d 417: 1.  Facts

2.  Court Holding: a)  A lessee’s implied duty to market does not include a duty to notify purchasers of the address

of the lessor b)  The implied duty to market does not include the duty to pay royalties in the event that the

purchaser does not pay them. c)  Tompkins satisfied the implied duty to market by arranging for the sale of the oil at the posted

price on the customary terms in the area.

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Royalty Clauses: Implied Covenant to Market Parker v. TXO Production Corp. & Delhi Gas Pipeline

Park v. TXO Production Corp. & Delhi Gas Pipeline Corp, 716 S.W.2d 644: 1.  Facts

2.  Court Reasoning:

We agree with appellants that the sale of gas from Texas to its subsidiary is inherently suspect. The record reflects that at the time of Texas' sale of the gas to Delhi, the other pipelines were offering the maximum legal rate for natural gas. Delhi also offered this maximum price, but then deducted a five percent compression charge, while the other prospective purchasers did not make such a deduction. The net effect of the compression charge was to reduce the price Texas (and hence its royalty interest holders) received to ninety-five percent of the going rate. We do not agree, however, that this fact alone means that Texas breached its implied covenant to market. In its per curiam opinion denying writ in the El Paso Court of Appeals' Pyote decision, the Supreme Court stated that “[a]lthough in a proper factual setting, failure to sell at market value may be relevant evidence of a breach of the covenant to market in good faith, it is merely probative and is not conclusive.” Thus, other factors must be examined when deciding whether Texas has breached its implied covenant with the appellants.

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Royalty Clauses: Implied Covenant to Market Texas Oil and Gas Corp. v. Hagen

Texas Oil and Gas Corp. v. Hagen, 1987 WL 47847: 1.  Facts

2.  Court Reasoning:

“Having determined the standard of conduct required of Texas lessees in fulfilling their marketing obligations, the issue becomes whether there is any evidence that TXO has failed to meet this standard. An oil and gas lessee breaches the implied covenant to reasonably market gas if the lessee fails to obtain terms in the gas sales contract that a reasonably prudent operator would have obtained. In light of the fact that the purchaser was a subsidiary, a prudent operator would have secured for itself and its lessors the right to receive sulphur royalties and would have reserved the right to renegotiate the contract price should the market value of the gas escalate. Indeed, TXO recognized such a duty when it entered into voluntary price redeterminations with Delhi on several occasions. We hold that there is evidence that TXO, as lessee, has failed to act as a reasonably prudent operator would have acted under the same or similar circumstances.”

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Royalty Clauses: Implied Covenant to Market Cabot Co. v. Brown

Cabot Co. v. Brown, 1987 WL 47847: 1.  Facts

2.  Court of Appeals Reasoning (716 S.W.2d 656):

“Appellee sought to prove intrastate market value, not interstate value. The issue of interstate value was, therefore, a defensive issue which appellant had the burden to submit at trial or bear the consequences of a deemed finding in support of the judgment. The gas produced from the leases in question were sold within Texas. While evidence of interstate gas price regulation may be admissible, such evidence does not bind the fact finder as a matter of law in its determination of market value.”

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Division Orders: Gavenda v. Strata Energy, Inc.

Gavenda v. Strate Energy, Inc., 705 S.W.2d 690: 1.  Facts

2.  Court Reasoning:

“When the operator, however, prepared erroneous orders and retained the benefits, we held that division orders were not binding. In Terrell, Stanolind Oil & Gas prepared the division orders and distributed the bonus and royalty accordingly. Stanolind Oil & Gas deducted the gross production tax from the bonus, although the lease provided that there would be no deductions. Despite the lease provision, Stanolind was shifting the gross production tax from itself to Terrell. It was profiting from its own error in drawing up the division order. There was unjust enrichment. Applying the law to this case, we hold that the division and transfer orders do not bind any of the Gavendas. Strata both erroneously prepared the division and transfer orders and distributed the royalties. Because of its error, Strata underpaid the Gavenda family by 7/16th royalty, retaining part of the 7/16th royalty for itself. It profited, unlike the operators in Exxon v. Middleton, at the royalty owner’s expense. It retained for itself, unlike in Chicago Cop. V. Wall, part of the proceeds owned to the royalty owners. Therefore, Strata is liable to the Gavendas for whatever portion of their royalties it retained, although it is not liable to the Gavendas for any of their royalties paid out to various overriding or other royalty owners.”

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Division Order Statute:

§91.402 of the Texas Natural Resources Code: (d)  THIS AGREEMENT DOES NOT AMEND ANY LEASE OR OPERATING AGREEMENT

BETWEEN THE INTEREST OWNERS AND THE LESSEE OR OPERATOR OR ANY OTHER CONTRACTS FOR THE PURCHASE OF OIL OR GAS.

(g)  Division orders are binding for the time and to the extent that they have been acted on and made the basis of settlements and payments, and, from the time that notice is given that settlements will not be made on the basis provided in them, they cease to be binding. Division orders are terminable by either party on 30 days written notice.

(h)  The execution of a division order between a royalty owner and lessee or between a royalty owner and a party other than lessee shall not change or relieve the lessee’s specific, expressed or implied obligations under an oil and gas lease, including any obligation to market production as a reasonable prudent lessee. Any provision of a division order between payee and its lessee which is in contradiction with any provision of an oil and gas lease is invalid to the extent of the contradiction.

(i)  A division order may be used to clarify royalty settlement terms in the oil and gas lease. With respect to oil and/or gas sold in the field where produced or at a gathering point in the immediate vicinity, the terms “market value,” “market price,” “prevailing price in the field,” or other such language, when used as a basis of valuation in the oil and gas lease, shall be defined as the amount realized at the mouth of the well by the seller of such prodution in an arm’s-length transaction.

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Division Order Statutes: Ohrt v. Union Gas Co.

Lessee drilled a well on the Lessor's tract and then pooled this tract with other acreage. Pooling clause allowed poolig of 320 acres but lessee pooled 690 acres in excess of what was authorized. Lessee sent D/O to Lessors showing the size of the unit (690 acres) and its effective date as the date of first production. Lessors signed the D/Os certifying their ownership of this pooled share of royalties. Lessee sent royalty checks calculated on the basis of the signed D/Os and Lessors cashed them every month. Lessors then realize that lease did not authorize pooling and demanded 100% of royalties from the date of production though January 14, 2001, the day before the Pooling Designation was filed of record. These 4 months of production amounted to $838,400 of underpaid royalties (stipulated by all parties). Held: Lessor had ratified and waived claims for these past royalties and was also estopped from claiming them. A jury had so found, and the judge affirmed the jury's answers to these issues. The rationale was simple: Lessor had signed D/Os and accepted royalties based on the Lessee's calculations, and subsection (g) of the D/O Act makes D/Os binding until revoked.

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Take or Pay and Royalty Owners:

Problem 7-70:

Assume that Pipeline Opossum has negotiated with Producer Pete to buy out the TOP provision in the Gas Purchase Agreement which governs all the gas sold in the Black gold field in Texas. In return, Producer Pete received a $20 million settlement from Pipeline Oppossum of all TOP liabilities. The royalty owners who signed leases with Producer Pete in this field hear about the settlement. They would like to receive 1/8 of the $20 million TOP settlement. Questions: 1.  Who wins and why?

2.  Suppose that the Royalty Interest Owners signed a division order that expressly provided for a share of any TOP proceeds or settlements received by the lessee to be paid to the lessors. Can a lessee invoke the Division Order Act and object to the language in the division order because it contradicts the lease?