Assume you own 150 acres of timber in Lycoming County. You decide to cut and clear 75 acres. You hire Big Logger, Inc. (“Big Logger”) to cut and sell the timber. Big Logger agrees to pay you a royalty of 25% of the proceeds received from the sale of your timber. As per your logging contract, Big Logger will sell the felled timber to third-parties. One of those third-parties is XYZ Furniture, who has agreed to take delivery of the felled timber at the edge of your driveway. It is your understanding that title to the timber will transfer at that location and that your royalty will be based on the sale proceeds Big Logger receives from XYZ Furniture at that same location.
Imagine, however, if Big Logger tried to deduct from your royalty the costs XYZ incurs to transport and move the felled timber from your farm to its processing facility in Towanda. The idea itself is preposterous and defies common sense. How can Big Logger deduct costs that are incurred after it sells the timber to XYZ Furniture? To most people, the notion that Big Logger can deduct XYZ’s costs from your royalty is illogical and simply absurd.
Yet, in the oil/gas world, this alarming practice is becoming more common. Gas drillers throughout the Marcellus region often try to deduct remote downstream costs from the landowner’s royalty. Unfortunately, a flawed decision recently issued by the federal district court in Ohio may encourage and embolden drillers to take such deductions. As detailed below, the federal district court in Henceroth v. Chesapeake Exploration, LLC, (4:15 CV 2591, Northern District of Ohio, September 30, 2019), erroneously concluded that the parties’ lease allowed the driller to deduct the downstream costs incurred by an affiliate.
In the winter of 2016, Mr. and Mrs. Henceroth and several other landowners in Columbia County, Ohio filed a class action lawsuit against Chesapeake Exploration. The suit alleged that Chesapeake Exploration breached Paragraph 5(B) of the parties’ oil and gas leases (the ” 2008 Leases”) by i) failing to actually market the gas and ii) wrongfully deducting downstream costs incurred after the gas was sold at the wellhead. Paragraph 5(B) of the 2008 Leases provided as follows:
5. PAYMENTS TO LESSOR. Lessee covenants to pay Lessor, proportionate to Lessor’s percentage of ownership, as follows: … (B) ROYALTY: To pay Lessor as Royalty, less all applicable truces, assessments, and adjustments on production from the Leasehold, as follows: 1. OIL: To delivery to the credit of Lessor, free of cost, a Royalty of the equal one-eighth part of all oil and any constituents thereof produced and marketed from the Leasehold. 2. GAS: To pay Lessor an amount equal to one-eighth of the net proceeds realized by Lessee from the sale of all gas and the constituents thereof produced and marketed from the Leasehold. Lessee may withhold Royalty payment until such time as the total withheld exceeds twenty-five dollars ($25.00). (emphasis added)
The landowners alleged that Chesapeake Exploration’s purported “sale” at the wellhead to an affiliate known as Chesapeake Energy Marketing (“CEM”) should not have been utilized as the royalty valuation point. Title to the gas was transferred to CEM at the wellhead and CEM then moved the gas downstream for further processing and eventual sale. CEM “paid” Chesapeake Exploration a fixed fee equal to “97%” of CEM’s weighted average sales price, less any compression, dehydration, transportation and processing costs incurred by CEM (the “CEM Price”). Chesapeake Exploration then calculated the landowner’s royalty based on the CEM Price it received at the wellhead, as opposed to the higher price obtained by CEM when CEM eventually sold the gas downstream. The landowners argued that the purported transaction at the wellhead to CEM did not constitute actual marketing of the gas and, therefore, could not be considered a “sale” for calculating their royalty. Specifically, the landowners contended that Paragraph 5(B) required Chesapeake Exploration to calculate the royalty on a “marketed” product and no such product existed until CEM moved and processed the gas downstream. As such, the landowners believed their royalty should be calculated on the proceeds realized at CEM’s downstream sale of the processed gas.
Alternatively, the landowners argued that Chesapeake Exploration could not pass through and deduct the downstream post-production costs incurred by CEM. The compression, dehydration, transportation and processing costs were incurred by CEM after it took title to the gas and, therefore, the landowners argued that those costs could not be deducted by the lessee, Chesapeake Exploration. The landowners’ theory was consistent with other cases which had addressed this same issue. See, Pollock v. Energy Corporation of America, 2015 LEXIS 79079 (W.D. Pa. June 18, 2015) (recognizing that the lessee could not deduct marketing and transportation charges incurred after title to the gas transferred to third party); Nani Resources Co. v. Asher Land & Mineral Ltd., 554 S.W.3d 323, 334 (KY 2018) (interstate pipeline charges not incurred by lessee are not deductible); Comm’r of the Gen. Land Office of Tex v. Sandbridge Energy Inc., 454 S.W.3d 603, 622 (Tex. App. 2014) (transportation charges not “actually incurred” not deductible). If the gas was “sold” at the wellhead to CEM as Chesapeake Exploration suggested, then, in that alternative, the landowners argued that no post-production costs were actually incurred by Chesapeake Exploration and consequently no costs could be assessed or charged against their royalty.
In February 2019, Chesapeake Exploration filed a motion for summary judgment. Chesapeake Exploration’s motion averred that no breach occurred as it had calculated and paid the royalty consistent with the express terms of Paragraph 5(B). Specifically, Chesapeake Exploration argued that, in accordance with Paragraph 5(B), it simply calculated the landowners’ 12.5% royalty on the “proceeds realized” from the CEM sale at the wellhead. Chesapeake Exploration further argued that although the CEM Price received at the wellhead was a “netback price” , such a pricing was not prohibited by Paragraph 5(B). In sum, Chesapeake Exploration simply argued that since it did not deduct any costs from the “proceeds” received at the wellhead, no breach of Paragraph 5(B) occurred as a matter of law.
The District Court agreed with Chesapeake Exploration and granted summary judgment in Chesapeake Exploration’s favor. In a rather perfunctory manner, the District Court opined that Chesapeake Exploration did not breach Paragraph 5(B) even though the purported CEM Price was artificially reduced by the deduction of remote downstream costs:
“…there are no genuine material facts in dispute. [Chesapeake Exploration] marketed, sold and transferred title to the oil and gas to [CEM] at or near the well-head, it received proceeds from [CEM] based on a netback price and did not take any deductions from the proceeds it received from the sale to [CEM]. [Chesapeake Exploration] is paid only the netback price from [CEM], not the third-party payee…”
The author submits that the District Court swung and missed on this one. First, the District Court failed to appreciate the significance of the term “marketed” in Paragraph 5(B). As noted by the federal district court in Chambers v. Chesapeake Appalachia, 359 F.Supp.3d 208 (W.D. Pa. 2019), the deliberate use of the term “marketed” in the royalty clause strongly suggests that the parties intended that the lessee (i.e., Chesapeake Exploration) and not an affiliate would actually sell the gas downstream. The Chambers court further opined that this, in turn, imposed on the lessee “a duty to reduce the gas to marketable form and sell it at a higher price than it would command at the well-head…” The court in Henceroth, however, failed to address or even acknowledge the non-delegable marketing duty created by Paragraph 5. The author contends this was clear error.
Second, the District Court failed to thoroughly examine the nature of the purported wellhead sale between Chesapeake Exploration and its affiliate CEM. Such transactions are inherently suspect and have been rejected by other courts. See, W.W. McDonald Land v. EQT Production, 983 F.Supp.2d 790 (S.D. W.Va. 2013) (“[T]he defendant cannot calculate royalties based on a sale between subsidiaries at the wellhead when the defendants later sell the gas in an open market a higher price”); Howell v. Texaco, 112 P.3d 1154 (Okla. 2004) (“an intra-company contract is not an arm’s length transaction [and] is not a legal basis on which a producer can calculate royalty payments”); Anderson Living Trust v. Conoco Phillips Company, 2016 WL 1158341 (D. New Mexico 2016) (“[T]he court will scrutinize non-arm’s-length transaction more closely than ordinary sales…”); Beer v. XTO Energy, 2010 WL 4767115 (W.D. Okla. 2010) (gas sales at wellhead between two controlled affiliated companies not appropriate for royalty calculation); Parker v. TXO Production Co., 716 S.W.2d 644, 647 (Tex. App. 1986) (“…sale of gas from lessee to its subsidiary is inherently suspect”). Nonetheless, the District Court in Henceroth treated the Chesapeake Exploration-CEM transaction as if it was an arms-length transaction and wrongfully assumed that the CEM Price was legitimate and consistent with market conditions. The author submits that this was also clear error.
Finally, the District Court erroneously allowed Chesapeake Exploration to indirectly deduct the downstream costs incurred by CEM. If the gas was legitimately sold at the wellhead, then no post-production costs should have been deducted from the landowners’ royalty. It is well-settled that costs can only be deducted if they are actually incurred by the lessee. See, Pollock v. Energy Corporation of America, supra. (“…it was improper for ECA to deduct interstate transportation charges as such charges were incurred after title passed to the third-party purchaser.”). In Henceroth, it was undisputed that title to the gas passed to CEM at the wellhead. As such, no costs could have been “incurred” by the lessee, Chesapeake Exploration, and none should have been deducted from the landowners’ royalty.
The Henceroth decision is unfortunate. It should be noted, however, that the opinion itself has no precedential value in Pennsylvania and is not binding on Pennsylvania courts. Nonetheless, the author is concerned that drillers in Pennsylvania may rely on the incomplete and faulty analysis utilized by the Henceroth court to justify more expansive deduction practices here in Pennsylvania.
1 A “netback” price subtracts out the downstream processing and transportation costs from the gross sales price of the product.