Let’s assume you own 95 acres in Greene County, Pennsylvania. In 2019, you signed an oil and gas lease with ABC Exploration. During the negotiations, you agreed that only those post-production costs which actually “enhanced” the value of the raw gas could be deducted from your royalty. In 2023, you receive your first royalty statement from ABC Exploration. You are pleased that there are no deductions for the cost to gather, compress or dehydrate the gas. However, you are shocked that significant processing costs are being deducted from your royalty. You contact ABC Exploration for an explanation. They claim that the costs incurred to process and fractionate the natural gas liquids (“NGLs”) are deductible because they “enhanced” the value of the raw gas. According to ABC Exploration, the individual NGL purity products, such as propane, butane and pentane, do not exist until the gas is processed and fractionated at a downstream processing plant. ABC Exploration contends that all costs incurred to process and fractionate the gas, and thereby create the “new” NGL purity products, must necessarily “enhance” the value of the raw gas. You are frustrated, angry and confused. Your 2019 Lease says no costs can be deducted unless such costs enhance “the value of the marketable oil, gas or other products …” Aren’t the NGLs a separate and distinct “product” that must first be marketable before any deductions are allowed? A recent decision by the Federal District Court in Ohio suggests that ABC Exploration cannot deduct the processing and fractionation costs. This is good news for landowners with Market Enhancement Clauses.
Before we address the substance of District Court’s decision, a brief primer on Market Enhancement Clauses is warranted. Many Pennsylvania oil and gas leases have what is commonly known as a “market enhancement” royalty clause (“MEC”). These MEC leases typically prohibit the deduction of any post-production costs that are incurred transforming the raw gas into a marketable product. Once gas is in a marketable form, the MEC generally allows the driller to deduct further costs only if those costs actually enhance the value of the gas product. The enhancement costs must also result in the driller obtaining a “better” price for the raw gas. In other words, the driller cannot deduct the cost of dehydrating the raw gas and then moving the gas 165 miles away to a distant buyer unless the final net sales price at that location is better than the price the driller would have received selling the gas locally. The driller must show that the purported enhancement cost resulted in a better sales price for that volume of marketable gas. See, Net-Back Method Does Not Result In Better Pricing To Justify Deductions Under Market Enhancement Clause (October 16, 2021). This makes sense. Incurring costs and receiving a “worse” price makes no sense. The key is that no post-production costs are deductible until the gas product is marketable. Despite this clear language, drillers often deduct all post-production costs regardless of whether the gas is in marketable form and regardless of whether the downstream costs actually enhanced the value of the gas product.
A frequent narrative asserted by drillers is that gas is always marketable at the well head and that all costs incurred downstream from the well head necessarily enhance the value of the raw gas. This is not accurate. In the Marcellus Shale region, gas is rarely sold at the well head as there is generally no competitive or consistent market at that location. Most shale gas is sold on the intrastate pipeline network. Given the lack of any true marketplace at the well head, an argument can be made that the gas is not marketable until the driller moves that gas to the actual marketplace (i.e., the interstate pipeline network). See, Pummill v. Hancock Exploration, LLC, 414 P.3d 1268 (Okla. Ctr. App. 2018) (gas not in marketable form until it reaches the intended market for that gas); Cooper Clark Foundation v. Oxy USA, Inc., 469 P.3d 1266 (Kansas Ctr. App. 2020) (“[T]he concept of marketability is tied to the market for the gas”). As such, the costs incurred dehydrating and moving the gas from the well head to the interstate pipeline network should not be deductible under a typical MEC. See, Kansas Court Rules That Gas Is Not Marketable Until It Reaches Interstate Pipeline (August 7, 2020). Likewise, the cost of processing the gas and separating the heavier hydrocarbons (i.e., the NGL purity products) from the gas stream should not be deductible until each individual NGL “product” is marketable. The recent decision in Grissoms LLC v. Antero Resources Corporation (U.S. District Court for the Southern District of Ohio, 2:20-cv-2028, August 4, 2023) supports this interpretation of the MEC and undermines the drillers’ argument that marketability automatically exists at the well head.
Grissoms was a class action that arose out of the form oil and gas lease utilized by Antero Resources Corporation (“Antero”) in 2012 throughout Noble, Belmont and Monroe counties in Ohio (the “2012 Leases”). The 2012 Leases all contained the same MEC, which provided as follows:
It is agreed between the Lessor and Lessee that, notwithstanding any language contained in A) and B) above, to the contrary, all royalties or other proceeds accruing to the Lessor under this lease or by state law shall be without deduction directly or indirectly, for the cost of producing, gathering, storing, separating, treating, dehydrating, compressing, processing, transporting, and marketing the oil, gas and other products produced hereunder to transform the product into marketable form; however, any such costs which result in enhancing the value of the marketable oil, gas or other products to receive a better price may be proportionally deducted from Lessor’s share of production so long as they are based on Lessee’s actual cost of such enhancements. However, in no event shall Lessor receive a price per unit that is less than the price per unit received by Lessee.
Pursuant to the 2012 Leases, Antero drilled 173 wells into the Utica Shale Formation in and around 2013 (the “Subject Wells”). Shortly thereafter the Subject Wells began producing liquid-rich gas, also known as “wet” gas. The liquid-rich gas had a BTU heat content that exceeded interstate pipeline specifications. As such, the gas had to be processed in order to render it pipeline quality. The Subject Wells were connected to a comprehensive gathering, compression and fractionation system known as the “Seneca System”. As the raw unprocessed gas moved through the Seneca System, it was treated and processed and eventually rendered pipeline quality. A brief summary of the Seneca System is germane to the underlying royalty dispute and the District Court’s ultimate ruling.
The raw “wet gas” produced from the Subject Wells was moved from the various well pads to the Seneca Processing Plant owned by Markwest Energy Partners (“Markwest”). At the Markwest facility, the gas was further processed into two (2) individual gas streams: a residue gas stream and a NGL mixture known as “Y-Grade.” The processing reduced the BTU heat content of the “dry” residue gas to levels compatible with interstate transmission pipeline specifications. As such, Antero could move the residue gas via those pipelines to distant markets. The Y-Grade stream, however, was not yet pipeline ready and required further processing.
The Y-Grade stream was then moved to the Hopedale Fractionation Facility in Jewett, Ohio. At Hopedale, fractionation occurred by heating the Y-Grade to allow for the separation of the individual NGLs based on their differing boiling points. As a result, the Y-Grade stream was converted into separate NGL purity products such as ethane, propane and butane. These individual components were then separately marketed and sold by Markwest on Antero’s behalf or directly by Antero.
Antero incurred various costs as the liquid-rich gas moved through the Seneca System. For example, Antero incurred gathering and compression costs to move the raw gas from the well-pads to the Markwest facility. In accordance with the MEC, Antero did not deduct those costs from the Landowners’ royalty. Antero also incurred costs associated with the processing at the Markwest facility as well as the fractionation at Hopedale. These costs were deducted from the Landowners’ royalty. Antero contended that the raw, unprocessed gas was “marketable” at or near the well pads. As such, all costs incurred downstream from that physical location were deductible if they “enhanced” the value of the raw gas. The Landowners disagreed and filed suit in April 2020.
In their Complaint, the Landowners argued that the processing and fractionation costs were not “enhancement” costs and therefore could not be deducted from their production royalty. The Landowners contended that each individual gas product produced form the Subject Wells must be “marketable” before any costs can be deducted with respect to that individual product. As support for this contention, the Landowners focused a single phase in the MEC:
“however, any such costs which result in enhancing the value of the marketable oil, gas or other products ….”
The Landowners asserted that the NGLs were a separate and distinct “other product”. Under the Landowners’ logic, since the NGL purity products did not even exist as a marketable product until the fractionation process was completed at Hopedale, none of the NGL processing or fractionation costs were deductible. In essence, the Landowners argued that the costs to process and fractionate the gas were not enhancement costs: they were costs necessary to transform the gas into another marketable product (i.e. the NGL purity products).
Conversely, Antero argued that the phrase “oil, gas and other products” in the MEC referred to the same product: unprocessed gas. Because that product was theoretically marketable prior to processing, the costs to process and fractionate that product (i.e. the unprocessed gas) were deductible enhancement costs. In other words, under Antero’s interpretation, the NGL purity products were simply another “form” of the unprocessed gas. And since the unprocessed gas was marketable at or near the well pad, all costs downstream from that location which “enhanced” the value of the unprocessed gas were deductible.
The District Court for the Southern District of Ohio disagreed and entered summary judgment in favor of the Landowners. The District Court was persuaded by the reasoning adopted by the Fourth Circuit Court of Appeals earlier this year in Corder v. Antero Resources Corporation, 57 F.3d 384 (4th Cir. 2023).
At issue in Corder was a nearly identical MEC. The Fourth Circuit in Corder rejected a similar argument as the one advanced by Antero in Grissoms and opined that the MEC “is not concerned with when ‘gas’ first reaches a marketable form, but rather when the particular ‘gas’ product sold does.” The Corder panel was also influenced by the fact that the MEC referred to plural “products” – strongly suggesting that the lessee may produce and sell multiple products derived from the original raw gas stream. Given such language, the Corder panel opined that each individual gas product must be in marketable form before any enhancement costs associated with that product can be deducted.
The Grissoms court found the Corder rationale compelling:
“[T]he Court is persuaded by the Fourth Circuit’s sound reasoning in Corder and adopts its interpretation of the contract at issue. The phrase “gas products” means residue gas, and “other products” means NGL purity products because these are the gas products that Antero actually sold from the Seneca System.”
Following the directive of Corder, the Grissoms court concluded that Antero‘s focus on the unprocessed gas was misplaced. The NGL purity products were separate and distinct products from the residue gas. The Grissoms court therefore ruled that the NGL purity products were not in marketable form until fractionation was completed at Hopedale. As such, no costs incurred prior to this physical location could be deducted under the MEC.
The author submits that the Grissoms court made the right call here. The analysis under any MEC must focus on when each individual “product” became marketable. And both Grissoms and Corder rejected and repudiated the drillers’ narrative that gas is always marketable at the well head. See, Market Enhancement Clauses in Pennsylvania After Dressler Family LP v. PennEnergy Resources LLC (October 25, 2022). It is believed that the Grissoms and Corder opinions may reflect a growing judicial trend which currently recognizes that the determination of marketability is fact intensive and cannot be subject to a “one size fits all” mentality. This is good news for landowners with MEC leases. Although not binding on Pennsylvania courts, the Grissoms opinion provides a logical and persuasive framework for MEC cases here in the Commonwealth.
