On The Rocks Presentation - Royalty Calculations: Deducting Post-Production Costs (June 2015)
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Download slides on Royalty Calculations: Deducting Post-Production Costs," presented by Senior Associate, Matthew Lichtenauer in June 2015. For questions, please contact Matthew Lichtenauer at mlichtenauer@burlesonllp.com.
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On The Rocks Presentation - Royalty Calculations: Deducting Post-Production Costs (June 2015)
- 1. 2015 Burleson LLP Matthew W. Lichtenauer
- 2. Royalty Calculations: Deducting Post-Production Costs 6/30/2015 2
- 3. Production vs. Post-Production Costs • Production Costs – Exploring – Drilling – Producing • Post-production costs – Transportation – Treating – Processing – Gathering – Compression – Marketing – Dehydration 3
- 5. Diagram for Gas 5 **Source: Exhibit to Occidental Permian’s Oral Argument in French v. Occidental Permian Ltd., 440 S.W.3d 1 (Tex. 2014)
- 6. Market Value vs. Proceeds Market Value • “the market value at the well of one-eighth of the gas so sold” • The price a willing buyer, not forced to buy, would pay a willing seller, not forced to sell Proceeds • “the royalty shall be one- eighth of the amount realized from such sale” 6 Newer leases often use language that is a combination of both, becomes more difficult to determine which it falls under. (bifurcated)
- 7. General Rule • A lessee may deduct for post-production costs as long as they are reasonable – Or any costs incurred by a lessee after the wellhead, whether to improve the quality of the production or to transport it to market, may be shared proportionately by the lessee and lessor • Other jurisdictions – First Marketable Product Approach 7
- 8. Market Value Background • Texas Oil & Gas Corp v. Vela – This court rejected the idea that contract proceeds equaled market value as a matter of law • Exxon Corp. v. Middleton – This court followed the reasoning held in Vela and held that for purposes of determining the market value, gas would be considered sold at the time when it was delivered, and not as of the effective date of long term purchase contracts 8
- 9. Heritage Resources, Inc. v. NationsBank • In Heritage, a trustee for gas interest royalty owners brought suit against Heritage Resources to recover transportation costs which were deducted when calculating royalty payments • The court held that Heritage Resources properly deducted transportation costs despite clauses in the lease prohibiting the deduction of post-production costs 9
- 10. Heritage Resources, Inc. v. NationsBank • The court focused on the language of “the market value at the well” of the gas produced • The court noted that there are two methods to determine market value at the well: – Comparable sales which are sales comparable in time, quality, quantity, and availability of marketing outlets (most desirable method) – Subtracting reasonable post-production costs from the market value at the point of sale (note court used market value again here but seems the court meant actual market price) 10
- 11. Heritage Resources, Inc. v. NationsBank • Court held that the commonly accepted meaning of “royalty” and “market value at the well” renders the post-production clauses prohibiting their deductions to calculate royalty in each lease as surplusage • In other words, when a lease prohibits deductions from royalty but royalty is valued at the wellhead, the lease still permits deductions of post-production costs to arrive at a wellhead price 11
- 12. Warren v. Chesapeake Exploration, L.L.C. • Three different leases: • Warrens’ Leases: – Royalty: as royalty, Lessee covenants and agrees … (b) to pay Lessor for gas and casinghead gas produced from said land (1) when sold by Lessee, [22.5%] of the amount realized by Lessee, computed at the mouth of the well…. [emphasis added] 12
- 13. Warren v. Chesapeake Exploration, L.L.C. • Third Lease - Javeed’s Lease • Royalty: as royalty, Lessee covenants and agrees … (b) to pay Lessor for gas and casinghead gas … 20% of the amount realized by Lessee, computed at the mouth of the well … [emphasis added] • Addendum: – Notwithstanding any of the provisions contained in the oil and gas lease to which this exhibit is attached, the following provisions shall apply: – The royalties to be paid by lessee are: … “the market value at the point of sale of 20% of the gas so sold or used” [emphasis added] 13
- 14. Warren v. Chesapeake Exploration, L.L.C. • Why were these 3 leases treated differently? – Location of the valuation of the gas – Warren Leases – “computed at the mouth of the well” – The court stated that the addendum does not change the point at which all royalty is computed (being the mouth of the well). – Javeed Lease – “the market value at the point of sale of 20% of the gas so sold or used” – This moves the valuation away from the mouth of the well 14
- 15. Potts v. Chesapeake Exploration, L.L.C. • Lessors sued arguing that Chesapeake improperly calculated the royalty payments by deducting post-production costs 15
- 16. Potts v. Chesapeake Exploration, L.L.C. • The royalties to be paid by Lessee are … on gas … the market value at the point of sale of 1/4 of the gas sold or used … [emphasis added] • The court permitted post-production cost deductions 16
- 17. Potts v. Chesapeake Exploration, L.L.C. • Why, when the valuation was set at the point of sale? – The court stated that when gas is sold at the wellhead, there are typically no costs of compression, dehydration, treatment or transportation. And when there are no such costs at the wellhead, the market value is in fact “free of all costs and expenses” • Did the plaintiffs argue the location of sale was not at the well because it was sold to affiliates? 17
- 18. Chesapeake Exploration, L.L.C. v. Hyder • This case is currently being decided by the Texas Supreme Court. Oral arguments were made in March of this year. 18
- 19. Chesapeake Exploration, L.L.C. v. Hyder • Again, Chesapeake uses a weighted average sales price to calculate the royalty and reduced the royalty amount by certain transportation costs paid by Chesapeake to unrelated pipeline companies • District Court and the Court of Appeals held that the transportation costs could not be deducted under the provisions of the lease 19
- 20. Hypo #1 • Parties have not specified whether deductions may be made and the point of valuation is at the wellhead – Yes, can deduct post-production costs 20
- 21. Hypo #2 • Parties have stated no deductions may be made and the point of valuation is at the wellhead – Yes, can deduct post-production costs 21
- 22. Hypo #3 • Parties have stated no deductions, valuation is at the point of sale, and sale is made at the well – Yes, according to Potts 22
- 23. HYPO #4 • Parties have stated no deductions, valuation is at the point of sale, and sale is made downstream – No 23
- 24. Checklist for interpreting Royalty Language 1. What does the lease say? a) Body vs. Addendum b) Proceeds vs. Market Value c) Where is the valuation point? 2. Where is the point of sale? a) At the well? b) Downstream? 3. Who is the gas sold to? a) Affiliate? b) Arms-length transaction to non-affiliate? Can I deduct that? 24
- 25. San Antonio Weston Centre 112 East Pecan Suite 700 San Antonio, TX 78205 T: 210.820.2625 F: 210.820.2609 Pittsburgh Southpointe Town Center 1900 Main Street Suite 201 Canonsburg, PA 15317 T: 724.746.6644 F: 724.746.6645 Midland Midland Tower 223 W. Wall Street Suite 400 Midland, TX 79701 T: 432.253.8600 F: 432.253.8601 Houston Pennzoil Place 700 Milam Street Suite 1100 Houston, TX 77002 T: 713.358.1700 F: 713.358.1717 Denver Wells Fargo Center 1700 Lincoln Street Suite 1300 Denver, CO 80203 T: 303.801.3200 F: 303.801.3201 New Orleans Poydras Center 650 Poydras Suite 1400 New Orleans, LA 70130 T: 504.299.3427 F: 504.299.3411 San Antonio Weston Centre 112 East Pecan Suite 700 San Antonio, TX 78205 T: 210.820.2625 F: 210.820.2609 Pittsburgh Southpointe Town Center 1900 Main Street Suite 201 Canonsburg, PA 15317 T: 724.746.6644 F: 724.746.6645 Midland Midland Tower 223 W. Wall Street Suite 400 Midland, TX 79701 T: 432.253.8600 F: 432.253.8601 Houston Pennzoil Place 700 Milam Street Suite 1100 Houston, TX 77002 T: 713.358.1700 F: 713.358.1717 Denver Wells Fargo Center 1700 Lincoln Street Suite 1300 Denver, CO 80203 T: 303.801.3200 F: 303.801.3201 New Orleans Poydras Center 650 Poydras Suite 1400 New Orleans, LA 70130 T: 504.299.3427 F: 504.299.3411 Thank You Matt Lichtenauer mlichtenauer@burlesonllp.com
Editor's Notes
- I would like to thank everyone here for coming out tonight. My presentation today is regarding what has become a very popular topic … oops not that one
- My presentation today is regarding what has become another popular topic, not quite as popular as the topic on the last slide, but has become more popular especially in today’s pricing climate where Lessor’s and Lessee’s alike are paying extra attention to income and costs. My presentation will cover some of the basic issues that come with various royalty provisions and the deduction of post-production costs.
- - First, let’s begin with defining production costs. - Think of these as costs or expenses incurred in finding the oil/gas and bringing them to the surface. Lessors are generally not burdened by these types of costs. That is one of the main differences as to what royalty interests are. Now we are going to look at post-production costs. There are a couple of ways to think about what is a post-production cost: An expense that is not required to bring the gas to the wellhead Amounts expended by the Lessee that add value to production in its raw state at the location of the wellhead prior to a final sale. In other words, those costs incurred by the Lessee after production is obtained up to the point where the product is sold. It is not always as simple as categorizing one of the above-listed costs as either production or post-production costs. For instance, compression may be treated as either/or production or post-production Where compression was done to increase production from a well, treated as a production cost Where compression done to create a marketable product in that it may be transported through pipelines, treated as a post-production cost Point out that gathering can be done from several wells on the same lease which would be a production cost versus gathering over a field-wide area with multiple leases might be treated as post-production Additionally, some of these are not extremely well defined or may be thought of as a bit amorphous. Especially what is considered marketing and gathering (***double check***) Earlier I mentioned that this issue usually focuses more on gas, but you can see where oil and gas are both similar: Gas may have to be dehydrated prior to purchase because gas that contains water is corrosive to pipelines Oil must also be dehydrated; however, water will normally separate itself from the oil in storage Both oil and gas may also contain other impurities
- As you can see from this diagram, the process of getting oil to the market is generally a simple process.
- Here we have a diagram for gas, and as can be seen here, there are generally more steps needed before there is a marketable product. Transportation vs gathering Hydrogen Sulfide removal Point out that gathering can be done from several wells on the same lease which would be a production cost versus gathering over a field-wide area with multiple leases might be treated as post-production
- For gas, there are two common royalty provisions: Market Value – “market value at the well of 1/8 of the gas so sold” Most commentators will point out that initially market value at the well was meant so that a lessee could calculate a fair wellhead value, when there was no actual value, by deducting transportation costs from the actual price received somewhere else (usually downstream) Proceeds – “the royalty shall be 1/8 of the amount realized from such sale” Being the proceeds derived from the actual sale of the gas Net Proceeds or Gross Proceeds Courts have held that Net Proceeds implies that post-production costs are deductible in that net proceeds must mean that the costs have been accounted for For some time now, it is very common to see a lease that has a bifurcated royalty provision. The lease well state that royalty is calculated using the market value for gas sold or used off the leased premises, and the royalty is calculated using the proceeds from the actual sale for gas sold at the well (on the leased premises)
- OK, so next let’s go to the general rule. A lessee may deduct for post-production costs as long as they are reasonable. Put another way, any costs incurred by a lessee after the wellhead, whether to improve the quality of the production or to transport it to market, may be shared proportionately between the lessee and lessor Touching something I mentioned early. If the expense is not required to bring the gas to the wellhead, then most likely it is a post-production cost If it is an expense that is not required to bring the gas to the wellhead, then most likely a post-production cost (SEE STCL LAW REVIEW ART) For purposes of the scope of this presentation, I am not going to go into detail about how other jurisdictions treat post-production costs. However, I know several of yall probably work outside of Texas so I just want to point out the other rule which is considered the minority rule. This rule is called the Marketable Product Approach? Under the lessee’s implied duty to market production, lessee bears the costs of any processes or other expenses which are necessary to make the gas into a marketable product. Some courts have even held that must establish these three requirements: (SEE STCL LAW REVIEW) Colorado, Kansas, Oklahoma, and West Virginia
- These cases looked only at the plain meaning of the language used in the leases to come to their conclusions. As will be seen in the next case, Heritage, you will see the court deviate from this method and look to the “commonly accepted meaning in the oil and gas industry.” Texas Oil & Gas Corp v. Vela Lessor entered into lease with lessee who entered into a long term gas purchase contract that set the price at gas for 2.3 cents/MCF. Many years later, the market price rose to approximately 13 cents/MCF. Lessors sued lessee and were successful in their claim that their royalty should have been a fractional share of 13 cents rather than the contract price of 2.3 cents. Exxon Corp v. Middleton This court followed the reasoning held in Vela and held that for purposes of determining the market value, gas would be considered sold at the time when it was delivered, and not as of the effective date of long term purchase contracts It should be noted that these cases seemingly deviated from what the industry use or understanding of the term market value
- What do the 3 leases state? Royalty is calculated by market value at the well Each lease includes provision prohibiting the deduction from royalty of certain post-production costs 3 different leases state: Each lease provided that lessor would receive a certain fraction of the market value at the well for all gas produced or sold off the premises In addition, each of these leases contained language prohibiting the deduction from royalty of certain post-production costs The court focused on the market value at the well language and noted that there are 2 methods to do this: 1) comparable sales 2) Subtracting reasonable post-production costs from the market value at the point of sale (note court used market value again here but seems the court meant actual market price) This method is circular in that the court calculated market value by starting with market value
- Court found that under the commonly accepted meaning of the terms “royalty” and “market value at the well,” the provisions prohibiting the deduction of post-production costs were surplusage As a result, the court held that the deductions made by Heritage Resources in calculating the Lessor’s royalty were properly made
- This is a US Fifth Circuit decision regarding three separate leases. The leases contained the same pre-printed royalty provisions which provided for valuations at the “mouth of the well.” Each lease included an exhibit that attempted to preclude deductions of post-production costs. The first 2 leases (The Warren Leases) included the same provision as seen on this slide. 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. The Addendum further provides: 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.
- Now we move to the third lease involved in this opinion. The court interpreted this lease (Javeed’s Lease) a different way because the language used in its Exhibit. This Lease included the same pre-printed language as the Warren Leases, but its addendum stated the following: “the market value at the point of sale of 20% of the gas so sold or used” The court held that Javeed’s claim should not have been dismissed with prejudice
- So why were the 3 leases treated differently by the court? This rests on the location of the valuation of the gas Warren Leases – “value computed at the mouth of the well.” The addendum did not change the point at which the royalty is computed, and therefore, the no deductions language constituted “surplusage as a matter of law” because all gas, regardless of where the gas is sold, is computed at the mouth of the well which necessarily excludes such costs The court goes on to say that the Warrens could have specifically stated that Lessor was entitled to 22.5% of the actual proceeds of the sale, regardless of the location. Javeed Lease – “market value at the point of sale of 20% of the gas so sold or used.” This moves the valuation away from the mouth of the well
- Here we have another 5th Circuit decision. In this case royalty owners sued Chesapeake… Lessors leased land to Chesapeake Exploration, L.L.C. (Chesapeake). Chesapeake Operating, Inc. (COI) operates the lease on Chesapeake’s behalf and sells gas produced from the lease to Chesapeake Energy Marketing, Inc. (CEMI), at the wellhead on the lessors’ land. Thereafter, CEMI transports the gas through a gathering system and resells it to unaffiliated purchasers at gas pipeline hubs considerable distances away from the wellhead. CEMI then pays Chesapeake the weighted average sales price that it received when it sells the gas at the downstream locations, after deducting post-production costs that CEMI incurred from the wellhead to the various points of delivery. Finally, Chesapeake pays 1/4 of the price it receives from CEMI to the lessors This lease contained similar language to that used in Warren in that the royalties were based on the market value at the point of sale
- So what does the lease say? The royalties to be paid by Lessee are: … on gas … the market value at the point of sale of 1/4 of the gas sold or used The royalty provision then goes on to say: Notwithstanding anything to the contrary herein contained, all royalty 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 [emphasis added] Royalties to Lessor or leased substances not sold in an arms length transaction shall be determined based on prevailing values at the time in the area.
- What was the outcome in this case? The court permitted the deduction of post-production costs here because the gas was sold at the wellhead. Why did the court allow for the deduction when the lessors set the valuation at the point of sale? The court stated that when gas is sold at the wellhead, there are typically no costs of compression, dehydration, treatment or transportation. And when there are no such costs at the wellhead, the market value is in fact “free of all costs and expenses” Did the plaintiffs argue the location of sale was not at the well because it was sold to affiliates? They made this argument but there was a question if it was properly brought before the court, and in any event the court found that the lease states that if the lessee sells gas to an affiliate, the royalty is to be determined based on the prevailing values at the time in the area, but does not require the point of sale to be the point at which the gas is ultimately sold to a non-affiliated party
- This case dealt with royalty and overriding royalty owners who filed suit claiming that Chesapeake improperly deducted transportation costs (post-production) from their royalty amounts in violation of the leases terms against post-production costs. The lease even included language explicitly stating that the Heritage Resources case does not apply. - Overriding royalty interest - Anti-Heritage Language “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 provisions of this Lease.”
- Going back to what I said earlier, what a willing buyer and willing seller If affiliate changes point of valuation
- Thank you for yall’s time. I will be around the rest of the evening, feel free to come by and ask any questions you may have. Thanks again, have a great night.