Jacklin Romeo, Susan S. Rine, and Debra Snyder Miller v. Antero Resources Corporation

Opinion

No. 23-589 – Jacklin Romeo, Susan S. Rine, and Debra Snyder Miller v. Antero Resources Corporation FILED December 6, 2024 Justice Hutchison, concurring: released at 3:00 p.m. C. CASEY FORBES, CLERK SUPREME COURT OF APPEALS OF WEST VIRGINIA I concur with the majority opinion because it makes clear that this Court

stands by two corollary duties implied in every oil and gas lease: the duty of a producer to

get oil and gas to market for the best price that can reasonably be obtained, and the duty to

get oil and gas in a marketable condition so it may receive the best price. These duties,

embodied by Wellman1 and Tawney,2 are clear and straightforward. Nevertheless, the oil-

and-gas producer in this case has brazenly created confusion by attempting to rewrite the

duties with new, but ambiguous, wording. If there is novelty in this case, it arises from the

focus on lower-priced “wet gas,” a hydrocarbon soup laden with methane and natural gas

liquids (“NGLs”), and the producer’s decision to break the wet gas into its higher-priced

fundamental components for sale. It is a producer’s choice to strip NGLs away from the

raw methane and break the NGLs into their constituent hydrocarbon parts (like propane,

ethane, or butane), and then to market and sell each component at a much higher price to

separate markets.

The duty to market and the marketable-condition rule are simple to state: (1)

a lessee/oil-and-gas producer has an obligation to deliver oil or gas to a marketplace, in a

1 Wellman v. Energy Res., Inc., 210 W. Va. 200, 557 S.E.2d 254 (2001). 2 Estate of Tawney v. Columbia Nat. Res., L.L.C., 219 W. Va. 266, 633 S.E.2d 22 (2006).

1 form where it will obtain the best price reasonably possible, and sell it for that best price,

and (2) the lessor/owner of oil-or-gas rights is entitled to royalties based on the gross

proceeds received by the producer. “Gross proceeds” are nothing more than the money

received by the lessee at the first point of sale to an unaffiliated third-party purchaser in an

arm’s length transaction, and free from any deductions for the expenses incurred by the

lessee in getting the oil or gas out of the ground and to market in a sellable condition.

Royalties for oil and gas are to be based solely on the total proceeds received by the

producer from a true, impartial sale; they are not to be based on net proceeds calculated

through some arcane, constantly shifting, “death-by-a-thousand cuts” formula designed to

deplete the lessor’s royalty.

Moreover, these duties (or rules or covenants or obligations, however one

might characterize them) are implied in every oil-and-gas lease. “[T]he well-established

rule [is] that a covenant arising by necessary implication is as much a part of the contract

– is as effectually one of its terms – as if had been plainly expressed.” Brewster v. Lanyon

Zinc Co., 140 F. 801, 812 (8th Cir. 1905). That said, the duty to market and the marketable-

condition rule may, of course, be altered by the parties through clear expressions in their

writings.

In the context of this case, the application of the Wellman-Tawney duty to

market and marketable-condition rule is straightforward: every sale of a component of wet

gas is a “point of sale.” If the best price can reasonably be obtained by selling the wet gas

to a third party, then that sale is enough meet the Wellman-Tawney requirements because

2 the wet gas is obviously a marketable product. But, if the best price is to be found by

breaking the wet gas into its constituent parts, and then selling the parts to different

markets, each separate sale combines to form the gross proceeds of the sales.

Reading the oil-and-gas producer’s arguments in this case that challenge the

marketable-condition rule, along with the majority opinion and the opinions of my

dissenting colleagues, I thought of but one word: audacity. One of my dissenting

colleagues calls the producer’s arguments “a new wrinkle in a perennial problem.” That is

an understatement. The only reason such arguments are a perennial problem is because the

producers audaciously and repeatedly disregard the obvious meanings of terms like “first

point of sale” and, instead, mangle them into dazzling, perplexing puzzles designed to

overwhelm and bamboozle busy judges. I concur with the majority opinion because I

refuse to accept the repeated attempts by oil and gas producers to spread chaos and

confusion and rewrite Wellman and Tawney (cases which were, frankly, originally crafted

to interpret the ambiguous leases written by producers).

To understand the flaws in the producer’s arguments, I am deviating from

the facts of this case and setting out an analogous fact pattern: the point of sale of a house.

Homeowners often sell houses through a real estate agent. The agent’s contract specifies

the agent will receive a commission for a successful sale represented as a percentage of the

house’s final sale price. Let’s say a homeowner and an agent agree to sell a house for a

six-percent commission.

3 Let’s also say the homeowner has no idea what the house is worth, and so

hires an appraiser. The appraiser assesses the condition of the house and comparable

property sales and comes up with a suggested price: $500,000. That price is the value the

appraiser figures someone, somewhere, might be willing to pay for the house. The agent

then puts a sign in the yard and advertises the house for $500,000, thinking if it sells for

that price the six-percent commission will be $30,000.

Now, at this point, what is the agent’s fee? The agent got the property listed

in the “first available market;” it has reached the “point of marketability” where it can be

sold. Is the agent then entitled to a $30,000 commission? Of course not. The homeowner

has no cash in hand from a buyer, and the parties would have to actually consummate a

sale with a ready, willing, and able buyer before the agent receives a fee. Merely offering

the house for sale, making it available on the market, does not a sale make.

Now, let us presume that the only ready, willing, and able buyer to appear

offers a mere $400,000 for the house, and the buyer, under no duress or improper

compulsion, is willing to accept the $400,000 offer. Obviously, if the sale is completed,

the real estate agent is entitled to six percent of that amount (or $24,000). Nobody in the

real world would presume to argue that the agent should receive six percent of $500,000,

the price at which the house was listed in the first available market, because (as any

appraiser will tell you) the appraised value based on comparable sales is meaningless when

compared to an honest market sale. The fair market value is the actual price at which the

property changes hands between a willing buyer and a willing seller, neither being under

4 any compulsion to buy or to sell and both having reasonable knowledge of relevant facts.

See, e.g., W. Va. Dep’t of Transp., Div. of Highways v. W. Pocahontas Properties, L.P.,

236 W. Va. 50, 62, 777 S.E.2d 619, 631 (2015); United States v. Cartwright, 411 U.S. 546,

551 (1973).

Let’s adjust our facts. Say the homeowner rejects the $400,000 offer and

chooses to spend some money – assume $150,000 – on rehabilitating the house. When the

repairs are completed, a bidding war ensues, a new buyer rises to the top offering $600,000,

the best price reasonably possible, and the sale is quickly completed. What is the real estate

agent’s fee? The commission is supposed to be a six-percent share of the house’s final sale

price. Obviously, for everyone who has ever bought or sold a house, the agent would earn

a commission of $36,000. Under no circumstances could the homeowner insist, because

s/he had unilaterally chosen to expend $150,000 getting the house into a marketable

condition, that the real estate agent’s commission should be reduced by an amount equal

to six percent of those remodeling expenses ($9,000) as the agent’s share. And, again,

under no circumstances could the homeowner insist the agent take a commission based on

the advertised price of $500,000, its “first available market” price, because the agent’s

contract says the commission is based upon the final sale price, that is, the gross proceeds

received by the homeowner from the third-party buyer.

I offer this example to make concrete the term “point of sale.” I recognize

the facts are not spot-on with this case. But let’s be honest, everyone knows the point of

sale of a house, the point of sale of a car, the point of sale of a pack of chewing gum.

5 Clearly, the point of sale is where the transaction is completed, where money effectively

changes hands between a willing buyer and willing seller, neither being under any

compulsion to buy or sell and both having reasonable knowledge of the facts.

The same goes for oil, gas, or natural gas liquids: under the corollary duties

to market and get the mineral into a marketable condition, the first point of sale is the

marketplace where the transaction is completed. Moreover, expenses for acts by the

producer to get a mineral out of the ground and to the point of sale to an impartial third

party are, essentially, production costs3; anything that is done to the mineral by a third party

after the point of sale is a processing cost borne solely by some third party. The producer

cannot deduct production costs (like drilling for, dehydrating, or pressurizing gas) from the

lessor’s royalty because the choice to incur those production costs is exclusively in the

province of the producer. From the moment gas surges from the ground and the wellhead,

the producer has total control. The producer decides if, when, and where to sell the gas; if,

when, where, and how to upgrade it, to make it “marketable” so it will obtain the best price

3 For historical reasons, much of our caselaw makes a fallacious distinction between “production costs” and “post-production costs.” Production costs are, historically, regarded as the expenses of drilling for oil or gas and getting the minerals to the surface; historically, expenses after the minerals leave the wellhead are often called post-production costs. But in the modern era, all of these expenses – from the drilling of the well to delivering the mineral into a transmission pipeline – should be called by what they are: production costs. All states require the lessee to bear the costs of production, and “production” really does not occur until there is a marketable product. Hence, all expenditures by the producer getting a mineral out of the ground and to a profitable marketplace are nothing more than production costs which, historically, have always been borne exclusively by producers.

6 reasonably possible; and if, when, and where to fractionate it. The lessor has no say in

what the producer does to the minerals, how, when, or how much money will be expended.

Hence, it would be grossly unfair for the producer to randomly reduce the lessor’s royalty

for a portion of those expenditures without some consent by the lessor—say, by putting

explicit language in a lease or contract spelling out those post-wellhead, pre-sale costs.

Under Wellman and Tawney and other marketable-product rule cases issued

by courts across the nation, the idea of “marketability” is a simple concept. If there is any

confusion with the term marketability, that confusion is the result of resistance by lessee-

producers to the adoption of clear, categorical definitions, and so, in the absence of clear

standards, whether a producer has met its obligation to pay a royalty to a lessor based on

the best price that could be obtained for oil or gas in the marketplace is nothing more than

a typical question of fact for a trial court:

There is no special problem in defining marketability. Like all fact issues, the term can be subject to conflicting proof. But marketability remains a typical fact issue.

Initially, it appeared that the major marketable-product jurisdictions would identify specific functions – compression, gathering, dehydration, treatment, processing, transportation – and classify them as per se deductible or not deductible. . . . But per se categories drew criticism from lessees[/producers] for a different problem, namely, that a categorical approach was insufficiently flexible. In hopes that they could win at trial what they were not winning by category, lessees sought the very less certain system that . . . [lessees now use] to condemn the marketable-product rule.

Marketable-product standards have moved away from purely categorical standards, a change that has increased their flexibility but to some extent reduced the definitiveness of the

7 standard. . . . [I]t has been lessees, not lessors, who generally have resisted fixed categories in marketable-product jurisdictions. . . . [L]essees prefer fact variable tests because the more factual the standard, the more room they have to argue that gas is marketable “at the well” as long as any sales, even to third parties, occur in the vicinity of the wells in issue. Thus, it is an irony to see a commentator [or a court] . . . using a factual flexibility that lessees in marketable-product jurisdictions have championed as a reason to refuse to adopt the rule.

In addition, marketability is not as amorphous [as it may sound.] . . . The legal concept of “a market” connotes active buyers and sellers. It has been applied in many areas, including in hundreds of oil and gas cases about market value and antitrust cases that turn on market definition. The factual standard has led courts to reject as qualifying markets such nonmarket transactions as affiliate sales, isolated transactions, and transactions that are disguised service agreements with the true base price set at downstream locations.

John Burritt McArthur, Some Advice on Bice, North Dakota’s Marketable-Product

Decision, 90 N.D. L. Rev. 545, 564-65 (2014) (footnotes omitted, emphasis added).

Applied to West Virginia’s marketable-product rule, this Court’s guidelines in Wellman

and Tawney do not pose particularly difficult problems for factfinders. The facts, usually

the result of decisions taken unilaterally by the lessee-producer, may be complex, but no

more complex than any other dispute over economic issues. Our law is clear that, under

the duty to market and the marketable-product rule, it is the producer’s responsibility to

get the best sale price reasonably possible for oil or gas, and any costs incurred getting the

product to the point of sale belong solely to the producer (unless, of course, the parties’

agreement specifies otherwise). Where that point of sale occurred is an easy fact for juries

to resolve.

8 Which brings me to the oil-and-gas producer’s arguments in this case. They

are audacious because the producer brazenly asked the Court to ignore the obvious meaning

of “point of sale” in favor of a nebulous “point of marketability” or “first available market.”

Wellman and Tawney recognize implied duties to market oil and gas, and the corollary duty

to get the product into a marketable and sellable form. One commentator summarized the

duties this way:

The duty to market has three distinct applications. First, . . . the lessee has to take reasonable steps to provide a physical connection to a market. . . .

[Second, t]he lessee also must pay royalty on the best price reasonably possible. Some classic best-price cases involve self-dealing, situations where the conflict of interest is clear. . ..

[Third, a] majority of states and the federal government require the lessee to bear all or most of the cost of making oil and gas [into a] marketable product. One rationale is that there really isn’t “production” – and all states require the lessee to bear the costs of production – until there is a marketable product. Another is that when the lessee bears the implied duty to market, it must pay all related costs as it does with the other implied duties.

John Burritt McArthur, U.S. Oil and Gas Implied Covenants and Their Functions, 61

Rocky Mt. Min. L. Inst. 29-1, 22-24 (2015).

The producer’s argument in this case stretches the duties to market and to

prepare a marketable product to the absurd. Specifically, it claims a producer only has a

duty to make oil or gas marketable for its first available market, that is, to make it ready so

somebody, somewhere, might want to buy it for some rumored price; it does not have to

9 actually sell the oil or gas. The producer claims that because the producer’s vice-

president’s brother-in-law knows a guy who, he’s pretty sure, heard an East Overshoe

transmission company once bought wet gas for a particular price is enough to say wet gas

has reached a “point of marketability” in Harrison County, West Virginia. The producer

avers that any actions taken by the producer (or an agent of the producer) after the point of

“I could’ve sold it”—that is, actions to rehabilitate the wet gas, and to fractionate it to

obtain a more favorable price—are processing costs that must be shared by the lessor and

taken proportionally from the lessor’s royalty.

In the context of Wellman and Tawney, the producer’s “first available

market” argument is nonsensical. This theory is undeniably ambiguous: Exactly where on

the production stream that subjective point lies that oil or gas might be “first marketable”

is likely to be the source of robust debate and, more likely, litigation.4 The majority opinion

deftly points out that the producer’s language choices are wholly unsupportable by

Wellman and Tawney.

Moreover, the producer’s argument is wholly at odds with the positions taken

by the Legislative and Executive branches of this state. The West Virginia Legislature has

adopted at least three statutes incorporating the Wellman-Tawney marketable product rule

4 See Amicus Curiae Brief of the West Virginia Royalty Owners’ Association and West Virginia Farm Bureau in Support of Petitioners, 8, fn 5.

10 and placed all post-wellhead, pre-sale costs on the producer.5 As for the Executive branch,

the State’s leases expressly say that a producer may not deduct the cost of putting oil and

gas into a marketable condition from royalties due to the State of West Virginia. The

State’s leases with producers say, “Royalties under this Lease shall be based on the total

proceeds of sale of the Granted Minerals, exclusive of any and all production and/or post-

production costs.” SWN Prod. Co., LLC v. Kellam, 247 W. Va. 78, 95, 875 S.E.2d 216,

233 (2022) (Hutchison, J., concurring) (quoting the State’s form lease with an oil-and-gas 6 producer).

5 See W. Va. Code 22-6-8(e) (2018) (royalties on flat rate leases must be paid “free from any deductions for post-production expenses, received at the first point of sale to an unaffiliated third-party purchaser in an arm’s length transaction for the oil or gas so extracted, produced or marketed.”); W. Va. Code § 11-1C-10(d)(3) (2024) (placing all tax burdens on producers for oil-and-gas production but allowing deductions for the “the actual costs incurred to bring the subsurface materials (oil, natural gas, and natural gas liquids) up to the surface and convert them to marketable products.”); and W. Va. Code § 22C-9- 7a(l) (2022) (prohibiting operators of horizontally drilled wells from charging post- production expenses against certain royalties, and stating no part of the statute “alters the common law of this state regarding the deduction of post-production expenses for the purpose of calculating royalty.”). 6 Other state government leases in America employ the marketable-product rule, covering much of the nation’s oil and gas production. For instance, most oil- producing land in Alaska is owned by the State of Alaska, one of the largest oil producers in the country since the late 1970s. The first lease form used by the State “has been interpreted to incorporate a marketable-product rule along federal lines,” and the current lease form “expressly bars most field deductions. Thus, at present, most production in Alaska is . . . governed by terms that allow a marketable-product rule.” McArthur, 90 N.D. L. Rev. at 555-56. Texas and Louisiana, two states that are counted as “at the well” states that seemingly reject the rule, also “use versions of marketable-product rules in their own leases.” Id. at 553.

11 The largest lessor of oil-and-gas interests in America is the United States

Government. Its leases stretch from the Gulf of Mexico to the Alaskan tundra. While oil-

and-gas producers complain that West Virginia’s law is some sort of modern-day

aberration, history shows that, since the 1960s, producers on federal lands have been

required to pay royalties based on the total “value” of production. That term has been

interpreted to mean producers on federal lands were required “to put oil and gas into

marketable condition largely at their own expense” and “to bear marketability costs. It

shows that the marketable-product doctrine had a very influential application long before

natural gas was deregulated [in the 1980s].” McArthur, 90 N.D. L. Rev. at 551-52.

Under the marketable-product rule, the producer must take measures to

convert wet gas into a marketable product that a willing third-party buyer, in an arm’s

length transaction, pays for with currency. If the best price is reasonably found by selling

wet gas, then the producer’s obligation under the lease is complete; but if the best price is

found by dehydrating and compressing the natural gas, stripping out the Y-Grade mixture

of natural gas liquid products, separating the natural gas liquids into their constituent parts

(like ethane, propane, butane, etc.), and then selling the dry “residue” natural gas, ethane,

butane, etc. separately, then the price obtained at each of those points of sale forms the

basis for both the producer’s profits and the lessor’s royalty. To the layperson, this may

seem like an accounting challenge, but that is a choice made exclusively by the producer

who I am confident is up to the task. The lessor is absent from, and ignorant of, these

complicated choices and should not have royalties reduced by these choices in the absence

12 of a clear written agreement showing the lessor assented. The key thing to remember is

that the point of sale is where each part of the gas taken from the ground is sold, and that

money accumulates to form the “gross proceeds” that are the basis of the producer’s profits

and the lessor’s royalties.

As an aside, I was particularly amused by the producer’s repeated claim that

the marketable product rule is unfair because many oil-and-gas producers do not sell their

gas in the “local basin,” but instead “are able to transport gas to distant markets such as

the Gulf Coast, Chicago, or Detroit, to obtain a higher price.” (Emphasis added). The

phrase “are able” does a lot of lifting here, and makes it seem as though the producer

actually picks up the gas and carries it to a faraway locale for sale, but this is untrue. In

my decades on the bench, I have seen cases where gas is sold to a distant customer, and I

understand the reality of selling natural gas in the interstate marketplace is far different.

The reality is that a producer takes gas from a West Virginia well, makes it ready for

market, connects to a pipeline in West Virginia, and dumps in a quantity of methane gas;

anyone connected to that pipeline may extract those molecules of gas, whether a mile away

or five hundred miles. When a customer in Detroit or Baton Rouge needs gas, they contract

for gas with a faraway producer who will give them a good price. But the customer does

not actually take gas from the producer. Instead, the customer connects their building or

factory to their local gas company with a meter, and the meter happens to be connected to

an interstate transmission system, and the customer then sucks out the measured quantity

of gas they need. The customer then pays the producer. The customer might be hundreds

13 of miles away from West Virginia but probably consumed molecules of gas produced and

placed in the pipeline only a few miles away; might open their wallet or write a check a

thousand miles away from West Virginia; but the transaction is consummated (from the

producer’s perspective) the moment the gas is placed into a local, West Virginia pipeline.

That is the point of sale, and that is where the producer’s profits and lessor’s royalty are

calculated.

For courts, one compelling guideline is that facts matter. The law is

advanced in concrete steps based on the facts of each case, not on a parade of amorphous,

“the sky is falling” fears projected by one party or another. Here, the facts are that the

producer took a hydrocarbon-laden soup from a West Virginia well, in a mostly gaseous

form, and, through various methods, placed those hydrocarbons into a marketable

condition and sold them by putting them into one or more pipelines in exchange for cash.

The producer had no lease, contract, or other writing with the lessors specifying, in

advance, what methods the producer would employ in making the gas marketable or

seeking the lessor’s written consent to pay a share of the cost. This Court’s answers to the

district court’s certified questions were based on those facts.

Accordingly, I concur with the majority opinion: the duty to market, and the

corollary duty to get natural gas into a marketable condition, apply to situations involving

both dry gas and wet gas.