Francis Kaess v. BB Land, LLC

• Court: West Virginia Supreme Court
• Decided: June 6, 2025
• Docket: 23-522
• Status: Published

Opinion

IN THE SUPREME COURT OF APPEALS OF WEST VIRGINIA

January 2025 Term

_____________________ FILED June 6, 2025 No. 23-522 released at 3:00 p.m. C. CASEY FORBES, CLERK _____________________ SUPREME COURT OF APPEALS OF WEST VIRGINIA

FRANCIS KAESS, Plaintiff Below, Petitioner,

v.

BB LAND, LLC, Defendant Below, Respondent.

___________________________________________________________

Certified Questions from the United States District Court for the Northern District of West Virginia The Honorable Thomas S. Kleeh, Chief Judge Civil Action No. 1:22-CV-51

CERTIFIED QUESTIONS ANSWERED _________________________________________________________

Rehearing Granted: December 31, 2024 Submitted Upon Rehearing: April 22, 2025 Filed: June 6, 2025

J. Anthony Edmond, Jr., Esq. Charles R. Bailey, Esq. Michael B. Baum, Esq. Bailey & Wyant PLLC Edmond & Baum, PLLC Charleston, West Virginia Wheeling, West Virginia Counsel for Petitioner Mike Seely, Esq. Jill M. Hale, Esq. Foley & Lardner LLP

Joseph G. Nogay, Esq. Seltitti, Nogay and Nogay Weirton, West Virginia

Mark T. Stancil, Esq. Willkie Farr & Gallagher, LLP Washington, DC

Joseph L. Jenkins, Esq. Jay-Bee Companies Bridgeport, West Virginia Counsel for Respondent

CHIEF JUSTICE WOOTON delivered the Opinion of the Court.

JUSTICE ARMSTEAD, deeming himself disqualified, did not participate in the decision of this case.

JUDGE HARDY, sitting by designation

JUSTICE WALKER dissents and reserves the right to file a separate opinion.

JUSTICE BUNN dissents and reserves the right to file a separate opinion.

JUSTICE TRUMP concurs and reserves the right to file a separate opinion. SYLLABUS BY THE COURT

1. “‘“A de novo standard is applied by this court in addressing the legal

issues presented by a certified question[] from a federal district or appellate court.” Syl.

Pt. 1, Light v. Allstate Ins. Co., 203 W.Va. 27, 506 S.E.2d 64 (1998).’ Syllabus Point 2,

Aikens v. Debow, 208 W.Va. 486, 541 S.E.2d 576 (2000).” Syl. Pt. 1, Harper v. Jackson

Hewitt, Inc., 227 W. Va. 142, 706 S.E.2d 63 (2010).

2. “‘If an oil and gas lease provides for a royalty based on proceeds received

by the lessee, unless the lease provides otherwise, the lessee must bear all costs incurred in

exploring for, producing, marketing, and transporting the product to the point of sale.’ Syl.

Pt. 4, Wellman v. Energy Resources, Inc., 210 W. Va. 200, 557 S.E.2d 254 (2001).” Syl.

Pt. 3, SWN Prod. Co., LLC v. Kellam, 247 W. Va. 78, 875 S.E.2d 216 (2022).

3. “‘Language in an oil and gas lease that is intended to allocate between

the lessor and lessee the costs of marketing the product and transporting it to the point of

sale must expressly provide that the lessor shall bear some part of the costs incurred

between the wellhead and the point of sale, identify with particularity the specific

deductions the lessee intends to take from the lessor’s royalty (usually 1/8), and indicate

the method of calculating the amount to be deducted from the royalty for such post-

production costs.’ Syl. Pt. 10, Est. of Tawney v. Columbia Natural Res., LLC, 219 W. Va.

i 266, 633 S.E.2d 22 (2006).” Syl. Pt. 5, SWN Prod. Co., LLC v. Kellam, 247 W. Va. 78,

875 S.E.2d 216 (2022).

4. “Language in an oil and gas lease that provides that the lessor’s 1/8

royalty (as in this case) is to be calculated ‘at the well,’ ‘at the wellhead,’ or similar

language, or that the royalty is ‘an amount equal to 1/8 of the price, net all costs beyond

the wellhead,’ or ‘less all taxes, assessments, and adjustments’ is ambiguous and,

accordingly, is not effective to permit the lessee to deduct from the lessor’s 1/8 royalty any

portion of the costs incurred between the wellhead and the point of sale.” Syl. Pt. 11, Est.

of Tawney v. Columbia Nat. Res., L.L.C., 219 W. Va. 266, 633 S.E.2d 22 (2006).

5. Except as may be specifically provided by the parties’ agreement, there

is an implied duty to market the minerals in oil and gas leases which contain an in-kind

royalty provision. If, for whatever reason, a royalty owner/lessor does not or cannot take

physical possession of his or her share of the production under an in-kind royalty clause,

then, except as may be specifically provided by the parties’ agreement, the

producer/lessee may discharge its royalty obligation to the lessor in one of several ways:

the lessee may deliver the lessor’s share of the production to a pipeline purchaser or other

third-party purchaser near the wellhead, free of cost, and to the lessor’s credit, under the

terms of a division order or other contract in which the purchaser pays the lessor directly

for his or her share of the production; or, the lessee may buy the lessor’s share of the

production from the lessor on terms negotiated by the parties; or, if the lessee elects

ii neither of the foregoing options, then under the implied marketing covenant the lessee

must market and sell the lessor’s share of the production, on the lessor’s behalf, along

with the lessee’s own share of the production.

6. If, for whatever reason, the mineral owner/lessor of an oil and gas

lease containing an in-kind royalty provision does not take his or her percentage share of

the oil and gas in kind, and the producer/lessee elects to market and sell the lessor’s share

of the production on the lessor’s behalf, along with the lessee’s own share of the

production, then, except as may be specifically provided by the parties’ agreement, the

lessee shall tender to the lessor a royalty consisting of the lessor’s percentage share of the

gross proceeds, free from any deductions for postproduction 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.

iii WOOTON, Chief Justice:

This matter is before the Court upon an August 25, 2023, order of the United

States District Court for the Northern District of West Virginia, which certified the

following questions:1

Question No. 1: Is there an implied duty to market for [oil and gas] leases containing an in-kind royalty provision?

Question No. 2: Do the requirements for the deductions of post-production expenses from Wellman v. Energy Resources, Inc., [210 W. Va. 200, 557 S.E.2d 254 (2001)] and Estate of Tawney v. Columbia Natural Resources, L.L.C, [219 W. Va. 266, 633 S.E.2d 22 (2006)] apply to leases containing an in- kind royalty provision?

On November 14, 2024, this Court issued an opinion answering both of the

certified questions in the affirmative. Thereafter, on December 12, 2024, Respondent BB

Land, LLC (“BB Land”) filed a petition for rehearing, which was granted; a new

scheduling order was established; and re-argument was held on April 22, 2025. Upon

careful review of the parties’ original and supplemental briefs and oral arguments, the

1 West Virginia Code section 51-1A-3 (1996) provides:

The Supreme Court of Appeals of West Virginia may answer a question of law certified to it by any court of the United States . . . if the answer may be determinative of an issue in a pending case in the certifying court and if there is no controlling appellate decision, constitutional provision or statute of this state. 1 briefs of amicus curiae submitted both in the original appeal and in the rehearing

proceedings,2 the appendix record, and the applicable law, we again answer both of the

certified questions in the affirmative and remand this matter to the district court for such

further proceedings as that court may deem appropriate.

I. Facts and Procedural Background

As set forth in the district court’s August 25, 2023, order of certification,

Petitioner Francis Kaess (“Mr. Kaess”) owns certain mineral interests in approximately

103.5 acres of land located in Pleasants County, West Virginia. His interests are subject to

an oil and gas lease (“Base Lease”) dated January 6, 1979, to which BB Land is the

successor in interest. The lease grants BB Land the right to drill, explore for, and extract

oil and gas “to the depth of 5000 feet or to the Oriskany Sand,” which is also referred to as

the Marcellus Shale formation, and provides for royalties to be paid to Mr. Kaess as

follows:

In consideration of the premises the said Lessee covenants and agrees as follows:

To deliver to the credit of Lessor [predecessors in interest to Mr. Kaess] free of cost in the pipelines to which he may connect his wells, the equal one-eighth (1/8) part of all oil produced and sold from the leased premises [and]

2 We acknowledge the amicus curiae briefs filed by the West Virginia Royalty Owners’ Association and the West Virginia Farm Bureau, and the Gas and Oil Association of WV, Inc., and thank these entities for giving the Court the benefit of their respective positions on the issues. 2 To deliver to the credit of Lessors free of cost in the pipeline to which he may connect his wells, the equal one-eighth (1/8) part of all gas produced and marketed from the leased premises and the Lessors shall have the right to free gas from any such well or wells for hearing [sic] and lighting any building on or off the property, making their own connections therefor at their own risk and expense.

In or about March, 2018, BB Land began reporting production of oil and gas

from 64.093 of Mr. Kaess’ acres which had been “pool[ed] or combine[d] . . . with other

land, lease or leases in the immediate vicinity thereof”3 pursuant to a May 19, 2016, Pooling

Modification Agreement negotiated by the parties.4 Once production began and thereafter,

Mr. Kaess did not take his share of the oil and gas in-kind; rather, BB Land sold Mr. Kaess’

share and paid him a royalty based on his percentage of acreage contributed to the pool,

with certain post-production costs deducted therefrom.

Mr. Kaess filed suit in district court, alleging three causes of action: Count

One, payment misallocation; Count Two, improper deductions; and Count Three,

excessive deductions. The only cause of action relevant here is Count Two, wherein Mr.

Kaess alleged that BB Land had breached the lease by improperly deducting post-

production costs from his royalties in violation of this Court’s decisions in Wellman and

3 There are 624.5024 acres in the pooling unit. 4 The parties agree that nothing in the Pooling Modification Agreement is relevant to the questions certified by the district court. 3 Estate of Tawney.5 BB Land filed a motion for summary judgment on this count,

contending that it was “permitted to deduct such costs from [Mr. Kaess’] royalty because

he did not take his share of production ‘in-kind’ as contemplated by the Base Lease and so

[BB Land] was required to take his share of production to market along with its own share

of production to avoid waste.” The district court denied the motion, finding that Wellman

and Estate of Tawney apply not only to proceeds leases6 but also to in-kind leases.7

Arguing that the district court’s conclusion of law was simply an “Erie

guess”8 and was, in fact, wrong, BB Land subsequently filed a motion to certify one

question to this Court: “Do the requirements for the deductions of post-production

5 The district court stayed Count Three and part of Count One, pending arbitration, and granted summary judgment to BB Land on the remaining allegations in Count One, which challenged BB Land’s calculation of royalties based on Mr. Kaess’ contribution of acreage to the pooling unit rather than to “production from the boundaries of the P286 Well itself.” Additionally, the district court dismissed all non-arbitration claims against Jay-Bee Oil & Gas, Inc. and Jay-Bee Production Company, leaving BB Land as the sole defendant in the case. 6 “Proceeds” royalty provisions provide for the mineral owner to receive a royalty consisting of a monetary share of the proceeds the producer receives from the sale of the oil and/or gas produced under the lease. 7 “In-kind” royalty provisions provide for the mineral owner to receive a royalty consisting of a portion of the physical oil or gas produced, tendered at the wellhead.

8 See Am. Comp. Ins. Co. v. Ruiz, 389 So. 3d 1060, 1061 n.1 (Miss. 2024) (“Taking its name from Erie Railroad v. Tompkins, 304 U.S. 64, 58 S. Ct. 817, 82 L.Ed. 1188 (1938), an Erie guess occurs when, in the absence of a state statute or caselaw on point, a ‘federal court must divine and enforce the rule that it believes this court would choose if the case were pending here.’”) (citations omitted)).

4 expenses from [Wellman] and [Estate of Tawney] apply equally to leases containing an in-

kind royalty provision where the lessor is entitled to a share of the production as opposed

to the proceeds from a sale to a third party?” In an order entered August 25, 2024, the

district court detailed the relevant facts of the case and reviewed this Court’s precedents,

ultimately concluding that two questions of law presented supra were issue determinative

and that there exists no controlling precedent in this Court’s decisions.9

Accordingly, the court granted BB Land’s motion and certified the questions.

By Order entered June 14, 2024, we accepted the certified questions and set this matter for

oral argument. As noted supra, on November 14, 2024, we issued an opinion answering

both of the certified questions in the affirmative. Thereafter, on December 31, 2024, we

granted BB Land’s petition for rehearing, established a new scheduling order, and set the

matter for reargument.

II. Standard of Review

9 See W. Va. Code § 51-1A-3 (2016):

The Supreme Court of Appeals of West Virginia may answer a question of law certified to it by any court of the United States or by the highest appellate court or the intermediate appellate court of another state or of a tribe or of Canada, a Canadian province or territory, Mexico or a Mexican state, if the answer may be determinative of an issue in a pending cause in the certifying court and if there is no controlling appellate decision, constitutional provision or statute of this state.

5 It is well established that “‘“[a] de novo standard is applied by this court in

addressing the legal issues presented by a certified question[] from a federal district or

appellate court.” Syl. Pt. 1, Light v. Allstate Ins. Co., 203 W.Va. 27, 506 S.E.2d 64 (1998).’

Syllabus Point 2, Aikens v. Debow, 208 W.Va. 486, 541 S.E.2d 576 (2000).” Syl. Pt. 1,

Harper v. Jackson Hewitt, Inc., 227 W. Va. 142, 706 S.E.2d 63 (2010). This means that

“‘we give plenary consideration to the legal issues that must be resolved to answer the

question’ certified by the [district] court.” State v. Scruggs, 242 W. Va. 499, 501, 836

S.E.2d 466, 468 (2019) (citing Michael v. Appalachian Heating, LLC, 226 W.Va. 394, 398,

701 S.E.2d 116, 120 (2010)).

III. Discussion

A. Postproduction Cost Background

In the instant case this Court is “once again asked to wade into the waters of

postproduction costs[,]” an expedition that by necessity begins with a review of our

relevant precedents. See SWN Prod. Co., LLC v. Kellam, 247 W. Va. 78, 84, 875 S.E.2d

216, 222 (2022).

We first addressed postproduction costs in Wellman, where the

defendant/producer Energy Resources, Inc. (“Energy Resources” or “the producer”)

contended that it was entitled to deduct postproduction costs from the mineral owners’

royalties based on the following language in the parties’ lease agreement:

6 Lessee agrees to deliver to Lessor, in tanks, tank cars, or pipe line, a royalty of one-eighth (1/8) of all oil produced and saved from the premises, and to pay to Lessor for gas produced from any oil well and used by Lessee for the manufacture of gasoline or any other product as royalty one-eighth (1/8) of the market value of such gas at the mouth of the well; is [if] such gas is sold by the Lessee, then as royalty one-eighth (1/8) of the proceeds from the sale of gas as such at the mouth of the well where gas, condensate, distillate or other gaseous substance is found.

210 W. Va. at 203-04, 557 S.E.2d at 257-58 (emphasis added).10 The producer argued that

the emphasized language “indicat[ed] that the parties intended that the Wellmans, as

lessors, would bear part of the costs of transporting the gas from the wellhead to the point

of sale[.]” Id. at 211, 557 S.E.2d at 265. The Court did not squarely resolve that issue,

finding that “whether that was actually the intent and the effect of the language of the lease

is moot because Energy Resources, Inc., introduced no evidence whatsoever to show that

the costs were actually incurred or that they were reasonable.” Id.

Although the Court’s opinion in Wellman can be fairly characterized as

somewhat discursive, we formulated a syllabus point which was soundly grounded in this

10 The postproduction costs claimed in Wellman were substantial. The undisputed evidence was that Energy Resources drilled for gas on 23.5 acres owned by the Wellmans and thereafter sold it to Mountaineer Gas Company for $2.22 per thousand cubic feet. See 210 W. Va. at 204, 209, 557 S.E.2d at 258, 263. However, after deduction of claimed postproduction costs the “proceeds” upon which Energy Resources calculated royalties were reduced from $2.22 to $0.87 per thousand cubic feet. Id. Thus, for every thousand cubic feet of gas sold by Energy Resources for $2.22, the Wellmans would have received a royalty of $0.10875 rather than $0.2775.

7 State’s long-established practice11 and has survived more than two decades of challenge:

“If an oil and gas lease provides for a royalty based on proceeds received by the lessee,

unless the lease provides otherwise, the lessee must bear all costs incurred in exploring for,

producing, marketing, and transporting the product to the point of sale.” Id. at 202, 557

S.E.2d at 256, Syl. Pt. 4.

Five years later, in Estate of Tawney, we were squarely presented with a

single certified question involving the issue that had been deemed moot in Wellman:

In light of the fact that West Virginia recognizes that a lessee to an oil and gas lease must bear all costs incurred in marketing and transporting the product to the point of sale unless the oil and gas lease provides otherwise, is lease language that provides that the lessor’s 1/8 royalty is to be calculated “at the well,” “at the wellhead” or similar language, or that the royalty is “an amount equal to 1/8 of the price, net of all costs beyond the wellhead,” or “less all taxes, assessments, and adjustments” sufficient to indicate that the lessee may deduct post-

11 “[T]raditionally in this State the landowner has received a royalty based on the sale price of the gas received by the lessee. Citing Robert Donley, The Law of Coal, Oil and Gas in West Virginia and Virginia § 104 (1951), this Court noted that,

[f]rom the very beginning of the oil and gas industry it has been the practice to compensate the landowner by selling the oil by running it to a common carrier and paying to him [the landowner] one-eighth of the sale price received. This practice has, in recent years, been extended to situations where gas is found[.]”

Est. of Tawney, 219 W. Va. at 271, 633 S.E.2d at 27. 8 production expenses from the lessor’s 1/8 royalty, presuming that such expenses are reasonable and actually incurred.12

219 W. Va. at 268-69, 633 S.E.2d at 24-25 (footnote added). We acknowledged that other

jurisdictions have come to differing conclusions on this issue, but in light of West

Virginia’s “generally recognized rule that the lessee must bear all costs of marketing and

transporting the product to the point of sale[,]” id. at 272, 633 S.E.2d at 28,13 as well as

“our traditional rule that lessors are to receive a royalty of the sale price of gas,”14 id., we

held that,

[l]anguage in an oil and gas lease that is intended to allocate between the lessor and lessee the costs of marketing the product and transporting it to the point of sale must expressly provide that the lessor shall bear some part of the costs incurred between the wellhead and the point of sale, identify with particularity the specific deductions the lessee intends to take from the lessor’s royalty (usually 1/8), and indicate the method of calculating the amount to be deducted from the royalty for such post-production costs.

Id. at 268, 633 S.E.2d at 24, Syl. Pt. 10. Further,

[l]anguage in an oil and gas lease that provides that the lessor’s 1/8 royalty (as in this case) is to be calculated “at the well,” “at the wellhead,” or similar language, or that the royalty is “an amount equal to 1/8 of the price, net all costs beyond the wellhead,” or “less all taxes, assessments, and adjustments” is ambiguous and, accordingly, is not effective to permit the

12 In Estate of Tawney, the Circuit Court of Roane County had certified two questions to this Court which we reformulated into this single question. 13 Emphasis added. 14 Emphasis added. 9 lessee to deduct from the lessor’s 1/8 royalty any portion of the costs incurred between the wellhead and the point of sale.

Id., Syl. Pt. 11.

After Estate of Tawney, West Virginia law was settled that at least with

respect to leases containing a proceeds royalty provision, in the absence of express,

unambiguous language to the contrary, oil and gas producers could not deduct from mineral

owners’ royalties any portion of the producers’ postproduction costs incurred between the

wellhead and the point of sale.

A decade later, however, another certified question was presented to the

Court in Leggett v. EQT Production Co., 239 W. Va. 264, 800 S.E.2d 850 (2017): whether

postproduction costs could be deducted where the leases in question contained flat-rate

royalty provisions,15 which at that time were governed by the predecessor to West Virginia

Code section 22-6-8 (1994). Although flat rate leases by their express terms entitle mineral

owner/lessors only to a yearly sum certain, per well, per year – i.e., a payment in the nature

of a rent rather than a royalty – subsection (e) of the legislation prohibited the issuance of

permits for new drilling or for the reworking of existing wells unless the producer filed an

affidavit certifying that it would pay royalties of “one-eighth of the total amount paid to or

15 Flat-rate royalty provisions are those providing for payment to the lessor of a sum certain, per well, per year. 10 received by or allowed to the owner of the working interest at the wellhead[.]” Leggett,

239 W. Va. at 269, 800 S.E.2d at 855.16

Despite its recognition of Estate of Tawney’s holding that the phrase “at the

wellhead” was “ambiguous and, accordingly . . . not effective to permit the lessee to deduct

from the lessor’s 1/8 royalty any portion of the costs incurred between the wellhead and

the point of sale[,]” a majority of the Court in Leggett concluded that “neither Wellman nor

Tawney [were] applicable to an analysis of the ‘at the wellhead’ language contained in

West Virginia Code § 22-6-8(e).” 239 W. Va. at 276, 800 S.E.2d at 862. The Court

reasoned that

both Wellman and Tawney involved the leasing parties’ use of the term “at the wellhead” in their freely-negotiated leases. Accordingly, those Courts were free to utilize common law principles pertaining to oil and gas leases and contracts generally—the implied covenant to market and construction of a contract against the drafter, respectively—to interpret the lease and resolve the issue. Utilizing these common law principles to interpret a statute, however, is not legally sound.

16 The Legislature recognized that statutorily invalidating flat-rate royalty provisions would likely run afoul of the United States Constitution, Article I, Section 10, and the West Virginia Constitution, article III, section 4, which “proscribe the enactment of any law impairing the obligation of a contract.” W. Va. Code § 22-6-8(a)(4). Nonetheless, the Legislature found that it could validly exercise the police powers of the State to “discourage as far as constitutionally possible the production and marketing of oil and gas located in this state under the types of leases or continuing contracts described above[,]” id., referring to those providing “wholly inadequate compensation” to the owners of oil and gas interests in light of technical advances in production and marketing of the minerals. Id. § 22-6-8(a)(2). 11 Id. at 274, 800 S.E.2d at 860.17 In interpreting the language in the statute, a task for which

“[t]he primary rule . . . is to ascertain and give effect to the intention of the Legislature[,]”

the Court concluded:

[n]ot only is the “at the wellhead” language clearly indicative of a legislative intention to value the royalties paid pursuant to

17 In dicta, the majority in Leggett harshly criticized both Wellman and Estate of Tawney, going so far as to characterize those opinions as reflecting the Court’s “complete misunderstanding of the [oil and gas] industry” and its analyses as “nothing more than a re-writing of the parties’ contract to take money from the lessee and give it to the lessor.” 239 W.Va. at 277, 800 S.E.2d at 863 (citations omitted). Indeed, language in the majority opinion can fairly be read as suggesting that these opinions might be limited, or perhaps even overruled, in the future: “[H]owever under-developed or inadequately reasoned this Court observes Wellman and Tawney to be, the issue presently before the Court simply does not permit intrusion into these issues. We therefore leave for another day the continued vitality and scope of Wellman and Tawney.” Id. While this dicta in Leggett could be read as a suggestion that this Court might reexamine its understanding of the common law of West Virginia as it applies to postproduction cost issues, the passage of time has proved such prediction to be erroneous. Instead, the “continued vitality and scope of Wellman and Tawney” were subsequently affirmed not only by this Court but also by the West Virginia Legislature. See Kellam, 247 W. Va. at 80, 875 S.E.2d 218, Syl. Pts. 3 & 5; W. Va. Code § 22-6-8(e) (2018) (amending statute to overrule Leggett). As the United States Court of Appeals for the Fourth Circuit has succinctly observed,

in Kellam, the court dismissed Leggett’s criticism of Wellman and Tawney as “a somewhat indulgent frolic,” emphasizing that it “was mere obiter dicta and of no authoritative value.” Kellam, 875 S.E.2d at 225-26. The Kellam court confirmed that Tawney and Wellman “are the result of a reasonable and justifiable interpretation of this State’s common law.” Id. at 226. Thus, Leggett’s endorsement of the work-back method for flat-rate leases with “at the wellhead” language (which the West Virginia legislature has since overruled) has no bearing on the interpretation of the freely negotiated leases in this appeal.

Corder v. Antero Res. Corp., 57 F.4th 384, 395 (4th Cir. 2023). 12 the statute based on the unprocessed wellhead price, we do not believe that permitting lessors to benefit from royalties based upon an enhanced, downstream price without commensurately sharing in the expense to create the enhanced value effectuates the “adequate” and “just” compensation sought by the statute.

Id. at 279, 800 S.E.2d at 865.

The concurring Justice in Leggett, although agreeing that the words “at the

wellhead” as used in the statute were indicative of legislative intent to permit deduction of

postproduction costs from royalty payments, noted that what “the majority’s opinion

underscores is the necessity of the Legislature to address these policy-laden issues and

declare, by statute, the will of the State’s citizenry in this regard.” Id. at 285, 800 S.E.2d at

871 (Workman, J., concurring) (emphasis added). Further, “[w]here the Legislature’s

inaction in the face of such significant changes in the industry leaves this Court to intuit its

intentions and/or retrofit outdated statutory language to evolving factual scenarios, the will

of the people is improperly disregarded.” Id. The Legislature immediately accepted this

challenge and amended West Virginia Code section 22-6-8(e) (2018) in its first regular

legislative session following the decision in Leggett. The amendment, which adopted

wholesale the “point of sale” holdings in Wellman and Estate of Tawney, made it clear that

the majority in Leggett had wrongly “intuit[ed] its intentions”18:

To avoid the permit prohibition of § 22-6-8(d) of this code the applicant may file with such application an affidavit which certifies that the affiant is authorized by the owner of the working interest in the well to state that it shall tender to the

18 See Leggett, 239 W. Va. at 285, 800 S.E.2d at 872. 13 owner of the oil or gas in place not less than one eighth of the gross proceeds, 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 before deducting the amount to be paid to or set aside for the owner of the oil or gas in place, on all such oil or gas to be extracted, produced or marketed from the well. If such affidavit be filed with such application, then such application for permit shall be treated as if such lease or leases or other continuing contract or contracts comply with the provisions of this section.

W. Va. Code § 22-6-8(e) (emphasis added). It is fair to say that the Legislature’s

amendment to West Virginia Code section 22-6-8(e) validated the view expressed by the

dissenting Justice in Leggett, who observed that the majority’s interpretation of the

statutory language was “perversely inconsistent with the overarching remedial intent of the

flat-rate statute for a Legislature so passionately dedicated to ensuring the future flow of

adequate compensation to oil and gas landowners to have purposefully provided a

mechanism of royalty valuation specifically designed to curtail that compensation.” 239

W. Va. at 287, 800 S.E.2d at 873 (Davis, J., dissenting).

Thereafter, in Kellam, we were presented with four certified questions from

the United States District Court for the Northern District of West Virginia. We answered

the first of these questions, “Is [Estate of Tawney] still good law in West Virginia?”, in the

affirmative, noting that “neither the parties, nor the Leggett Court in criticizing the legal

underpinnings of Wellman and Tawney, have articulated any reason sufficient to justify the

overruling of those cases. Accordingly, we decline to do so[.]” Id. at 89, 875 S.E.2d at 227.

14 We reformulated the other certified questions into a single query: “What

level of specificity does Tawney require of an oil and gas lease to permit the deduction of

post-production costs from a lessor’s royalty payments, and if such deductions are

permitted, what types of costs may be included?” Id. at 81, 875 S.E.2d at 219. We

ultimately declined to answer the reformulated question because “[t]he answer to this

question necessarily involves the exploration of contractual language, the possible need for

interpretation of said language, and the development of facts to assist either the court or

the factfinder, as appropriate.” Id. at 81, 875 S.E.2d at 219. Nonetheless, in our discussion

we found it appropriate to

reiterate Tawney and Wellman’s succinct requirements that leases must meet in order to allocate some share of the post- production costs to the lessor. Specifically, the lease must: (1) include language indicating the lessor will bear some of those costs; (2) identify with particularity the deductions to be made (with an understanding that such deductions must be both reasonable and actually-incurred under Wellman); and (3) indicate the method of calculating the amount to be deducted.

Id. at 89, 875 S.E.2d at 227.

Finally, and critically, we noted the importance of stare decisis19 in promoting

uniformity and predictability in the law, concluding that “overruling Tawney and Wellman

19 See Syl. Pt. 2, Dailey v. Bechtel Corp., 157 W. Va. 1023, 207 S.E.2d 169 (1974) (“An appellate court should not overrule a previous decision recently rendered without evidence of changing conditions or serious judicial error in interpretation sufficient to 15 would result in instability and uncertainty, particularly for the thousands of leases that have

been executed in the years since those opinions were published.” Id. Accordingly, we

reaffirmed the continuing vitality of both Wellman and Estate of Tawney in syllabus points

three and five of Kellam as follows:

“‘If an oil and gas lease provides for a royalty based on proceeds received by the lessee, unless the lease provides otherwise, the lessee must bear all costs incurred in exploring for, producing, marketing, and transporting the product to the point of sale.’ Syl. Pt. 4, Wellman v. Energy Resources, Inc., 210 W. Va. 200, 557 S.E.2d 254 (2001).

....

Language in an oil and gas lease that is intended to allocate between the lessor and lessee the costs of marketing the product and transporting it to the point of sale must expressly provide that the lessor shall bear some part of the costs incurred between the wellhead and the point of sale, identify with particularity the specific deductions the lessee intends to take from the lessor's royalty (usually 1/8), and indicate the method of calculating the amount to be deducted from the royalty for such postproduction costs.” Syl. Pt. 10, Estate of Tawney v. Columbia Natural Resources, LLC., 219 W. Va. 266, 633 S.E.2d 22 (2006).

Kellam, 247 W. Va. at 80, 875 S.E.2d at 218, Syl. Pts. 3 & 5.

In summary, after Kellam, which expressly approved and reaffirmed the

holdings of Wellman and Estate of Tawney, and in light of the Legislature’s amendment

compel deviation from the basic policy of the doctrine of stare decisis, which is to promote certainty, stability, and uniformity in the law.”).

16 to West Virginia Code section 22-6-8(e), which amendment adopted the holdings of

Wellman and Estate of Tawney and thus effectively overruled Leggett, the law is settled

that at least with respect to proceeds royalty provisions and flat-rate royalty provisions, in

the absence of express, unambiguous language to the contrary, oil and gas producers

(lessees) cannot deduct from mineral owners’ (lessors’) royalties any portion of their costs

incurred between the wellhead and the point of sale.

B. Implied Duty to Market for Leases Containing an In-Kind Royalty Provision

With the foregoing background in mind, we turn to BB Land’s claim that a

producer/lessee may deduct postproduction costs from a mineral owner/lessor’s royalties

where the parties have entered into a lease containing an in-kind royalty provision, but the

mineral owner has not taken his or her one-eighth share of the gas or oil in-kind and the

producer has therefore taken the owner’s share to market in order to prevent waste.

In this regard, the district court first asks whether there is an implied duty to

market for leases containing an in-kind royalty provision.20 BB Land argues that there is

20 At the outset, we reject any implication in Mr. Kaess’ brief that the royalty provision in his lease is some sort of hybrid proceeds provision rather than an in-kind provision by virtue of its reference to royalties from “oil produced and sold from the leased premises” and to “gas produced and marketed from the leased premises.” (Emphasis added). This issue is not before us because in an order entered on July 21, 2023, the district court held that by virtue of Mr. Kaess’ failure to respond to a request for admission, it is deemed admitted “that the LEASE entitles YOU to receive YOUR royalty in-kind, as opposed to a percentage of proceeds received by [BB LAND] from the sale of any OIL, GAS, or NGLs.” 17 no such implied duty. More specifically, BB Land contends that its sole obligation under

the lease with Mr. Kaess is to deliver “one eighth (1/8) part of [the oil or gas] produced”

into “the pipe line to which [Mr. Kaess] may connect his wells[,]” and once this has been

accomplished BB Land has no further duties, express or implied, under the lease. There

are multiple problems with this argument.

First, BB Land contends that Wellman and Estate of Tawney were wrongly

decided because this Court, in its “dogged devotion” to Professor Donley’s treatise written

more than a half century earlier,21 failed to apprehend the changing landscape brought

about by deregulation of the oil and gas industry in the 1980’s and 1990’s, a process which

began in 1978 with passage of The Natural Gas Policy Act of 1978 (“NGPA”), 15 U.S.C.

§§ 3301-3432 (1982), and continued with Order 636 issued by the Federal Energy

Regulatory Commission (“FERC”) in 1992. Prior to passage of the NGPA, the price at

which producers could sell their gas to interstate pipelines was controlled by FERC, with

the result that most gas was sold by producers at or close to the wellhead; mineral owners’

royalties were calculated based on the price the pipeline companies paid the producers, and

Nonetheless, we find that the words “produced and sold” and “produced and marketed” add to the ambiguity of the Base Lease with respect to BB Land’s duties where, as here, Mr. Kaess did not take his royalties in kind. See discussion infra. 21 See Leggett, 239 W. Va. at 277, 800 S.E.2d at 863; Donley, supra note 11.

18 few postproduction costs came into play because it was the pipeline companies, not the

producers, who marketed the gas to local markets. As one court explained,

[p]rior to the restructuring, pipelines had performed both a merchant and a transportation function. That is, they typically engaged in “bundling,” selling to each customer both the required quantity of natural gas and transportation service bringing that gas from the production area to the customer’s point of purchase. . . . In the process of restructuring, the Commission concluded that bundling discouraged the sale of gas by non-pipeline sellers. Id. The Commission sought to remedy this “market power” situation and to establish a new regime ensuring “that all shippers have meaningful access to the pipeline transportation grid so that willing buyers and sellers can meet in a competitive, national market to transact the most efficient deals possible.” Order No. 636, ¶ 30,939, at 30,393. To achieve that goal the Commission required pipelines to “unbundle,” sell transportation services separately from gas, and thereby become primarily transporters as a competitive market developed for the merchant function.

NorAm Gas Transmission Co. v. F.E.R.C., 148 F.3d 1158, 1160 (D.C. Cir. 1998) (citation

omitted). Of relevance to this case, one upshot of deregulation was that producers were

now free to sell their product far downstream from the wellhead, which increased their

costs – but also allowed them to seek out the best prices available for their product outside

of local markets.

Contrary to respondent BB Land’s contention that we fail to appreciate the

impact of federal statutory and regulatory changes on the natural gas industry, this Court

does understand the changes resulting from deregulation, including the increased costs

borne by producers resulting from processing and transportation – costs which were 19 minimal or nonexistent prior to deregulation, when most gas was sold at or near the

wellhead. We are constrained, however, from making policy choices in order to determine

legal issues; Wellman, Estate of Tawney, and Kellam were all based on existing West

Virginia law, not on policy considerations. Weighing the interests of mineral owners in

maximizing their royalties versus the interests of producers in maximizing their profits is

a task for the Legislature, not for this Court. See, e.g., MacDonald v. City Hosp., Inc., 227

W. Va. 707, 722, 715 S.E.2d 405, 420 (2011) (“it is the province of the legislature to

determine socially and economically desirable policy”). In short, if the industry believes

that our precedents will have a deleterious impact on the viability of West Virginia’s oil

and gas industry, it needs to take those concerns to the Legislature, not to this Court.

Second, BB Land argues that Wellman and Estate of Tawney should be

understood as applying only where the producer sells the gas at or close to the wellhead, a

situation in which postproduction costs would be minimal or nonexistent. We reject this

argument because the facts of the cases do not bear out the underlying premise. As

previously discussed, in Wellman the postproduction costs claimed by the producer

reduced the proceeds upon which owner’s one-eighth royalty was calculated from $2.22

per thousand cubic feet to $0.87 per thousand cubic feet. See supra note 10. This refutes

any claim that the postproduction costs in Wellman were insignificant because the gas

didn’t have far to go, or that the Court’s decision in the case was in any way premised on

such an assumption. Further, in Estate of Tawney the Court noted that “CNR took

deductions from royalty owners in equal amounts regardless of the distance from the well

20 to TCO’s transportation line.” Est. of Tawney, 219 W. Va. at 269, 633 S.E.2d at 25

(emphasis added). Again, this refutes any claim that the case was based on the distance the

gas had to travel to get to the place of sale.

Third, BB Land contends that the in-kind provision of the parties’ Base Lease

is clear and unambiguous, and thus no implied duties come into play “to relieve one party

of a bad bargain.” Pechenik v. Baltimore & O. R. Co., 157 W. Va. 895, 898, 205 S.E.2d

813, 815 (1974). We disagree. Any language establishing in-kind royalties to be delivered

to an individual who does not have the infrastructure – wells or tanks or pipelines – to store

and then market his or her one-eighth share of the oil and gas produced, creates an inherent

conflict and thus an ambiguity.22 See Est. of Tawney, 219 W. Va. at 272-73, 633 S.E.2d at

28-29 (holding that leases which called for royalties based on gross proceeds “at the

wellhead” were ambiguous, as the language “could be read to create an inherent conflict

due to the fact that the lessees generally do not receive proceeds for the gas at the

wellhead.”). Additionally, the language in the lease at issue here contains a second layer of

ambiguity, as it establishes in-kind royalties on all oil produced and sold from the leased

premises and all gas produced and marketed from the leased premises. This language

makes no sense whatsoever where the producer tenders the owner’s share of the oil and

22 See Byron C. Keeling, Fundamentals of Oil and Gas Royalty Calculation, 54 ST. MARY’S L.J. 705, 711 (2023) (“most royalty owners do not have the tanks or other facilities or infrastructure necessary to physically possess any part [including their one-eighth share] of the oil and gas production.”). 21 gas at the wellhead, in which case both the duty to market and the deduction of

postproduction costs would be moot points.

BB Land urges us to adopt the holding of the Oklahoma Supreme Court in

XAE Corp. v. SMR Property Management Co., 968 P.2d 1201 (Okla. 1998), which held

that

[t]here is no duty either express or implied on the lessee in the case at bar to do other than deliver the gas to the overriding royalty owners in kind. The overriding royalty owners’ decision not to take the gas in kind does not impose different duties on the lessee.

Id. at 1207. We decline to follow the reasoning of XAE Corp. because the Oklahoma case

is inapposite to the case at bar. The court’s holding in XAE Corp. was specific to its facts:

the owners of the overriding royalty interest were not parties to the lease, and “implied

covenants of an oil and gas leases [sic] do not extend to lease assignments with reservation

of overriding royalty interest.” Id. at 1204 (emphasis added); cf. Gastar Expl., Inc. v.

Contraguerro, 239 W. Va. 305, 800 S.E.2d 891 (2017) (pooling agreements between

lessors and lessees do not require the consent or ratification of individuals holding

nonparticipating royalty interests because those individuals have conveyed both the oil

and gas in place and the executive leasing rights to the lessors). BB Land has cited no

cases in which the holding of XAE Corp. was applied to the lessor in an in-kind agreement

– here, Mr. Kaess. Rather, when Mr. Kaess failed to take his one-eighth share of the oil

and gas in kind, BB Land had three possible courses of action:

22 If, for whatever reason, a royalty owner does not or cannot take physical possession of its royalty share of the production under an in-kind royalty clause, then the lessee or producer may discharge its royalty obligation to the royalty owner in one of several ways:

(1) The producer may deliver the royalty owner’s share of the production to a pipeline purchaser or other third-party purchaser near the wellhead – free of cost, and to the royalty owner’s credit – under the terms of a division order or other contract in which the purchaser pays the royalty owner directly for its share of the production.

(2) The producer may buy the royalty owner’s share of the production from the royalty owner on terms that the producer negotiates with the royalty owner.

(3) Or, if the producer does not either buy the royalty owner’s share of the production or deliver the royalty owner’s share of the production to a purchaser free of cost, then under the implied marketing covenant, the producer must market and sell the royalty owner’s share of the production – on the royalty owner’s behalf – along with the producer’s own share of the production.

Keeling, supra at 711-12 (emphasis added) (footnotes omitted). This last option is the one

BB Land chose when Mr. Kaess failed to take his one-eighth share in-kind, thus

acknowledging by its actions the existence of an implied covenant to market Mr. Kaess’

share. Indeed, BB Land implicitly acknowledges this point in its brief, citing with approval

the case of Wolfe v. Prairie Oil & Gas Co., 83 F.2d 434 (10th Cir. 1936), where it was held

23 when [the lessor] failed either to provide storage or to arrange for the marketing of his share of the royalty oil, not only was [the lessee] impliedly authorized to sell it as his agent, but it became its duty so to do. Indeed, there was no other practical way for [the lessee] to take care of the royalty oil so as to avoid waste and loss; and there was no other way for it to comply with its lease covenant to deliver the royalty oil in the pipe line to the credit of the royalty owners.

Id. at 437 (emphasis added).

As set forth supra, this Court has judicially recognized the existence of an

implied covenant to market in leases containing proceeds royalty provisions, and the

Legislature has statutorily recognized the existence of an implied covenant to market in

leases containing flat-rate royalty provisions. We discern no principled basis on which to

hold that in-kind leases are somehow different; indeed, it would be totally anomalous if

this Court were to allow the deduction of postproduction costs where the parties’ lease

contains an in-kind royalty provision, while the Legislature has expressly disallowed such

deduction where the parties’ lease contains a flat-rate royalty provision – provisions

which are materially alike in that neither ties royalties to sale proceeds. See text infra. In

light of the foregoing, we agree with Justice Hutchison’s cogent observation that “the

fundamental goal implied into every single oil and gas lease is that the lessee has a duty

to extract the minerals and get them to market for sale.” Kellam, 247 W. Va. at 91, 875

S.E.2d at 229 (Hutchison, J., concurring) (emphasis added) (footnote omitted).

24 Accordingly, we answer the district court’s first certified question in the

affirmative and hold that except as may be specifically provided by the parties’

agreement, there is an implied duty to market the minerals in oil and gas leases which

contain an in-kind royalty provision. If, for whatever reason, a royalty owner/lessor does

not or cannot take physical possession of his or her share of the production under an in-

kind royalty provision, then, except as may be specifically provided by the parties’

agreement, the producer/lessee may discharge its royalty obligation to the lessor in one

of several ways: the lessee may deliver the lessor’s share of the production to a pipeline

purchaser or other third-party purchaser near the wellhead, free of cost, and to the lessor’s

credit, under the terms of a division order or other contract in which the purchaser pays

the lessor directly for his or her share of the production; or, the lessee may buy the lessor’s

share of the production from the lessor on terms negotiated by the parties; or, if the lessee

elects neither of the foregoing options, then under the implied marketing covenant the

lessee must market and sell the lessor’s share of the production, on the lessor’s behalf,

along with the lessee’s own share of the production.

C. Whether Postproduction Cost Deductions Apply to In-Kind Lease Royalty Provisions

We turn now to the district court’s second certified question: whether the

requirements for the deduction of postproduction expenses as set forth in Wellman and

25 Estate of Tawney apply to leases containing an in-kind royalty provision.23 In light of our

determination that there is an implied duty to market the minerals in all oil and gas leases,

including those leases which contain an in-kind royalty provision, this question requires

little discussion.24

BB Land argues that the requirements of Estate of Tawney and Wellman

should apply only to leases which provide for royalties based on the value or sale price

of the oil and gas produced, because the parties to in-kind royalty provisions did not

contemplate that the lessee would even possess the lessor’s share of the oil or gas after it

was produced, let alone market it. This was the view espoused by the majority in Leggett,

which wrote that “at the times these [flat-rate] leases were executed, the parties

contemplated neither the marketing of the product . . . nor cost allocation[,]” and thus

“post-production costs and the marketing efforts of the lessor [were] irrelevant to both

parties[.]” Leggett, 239 W. Va. at 276, 800 S.E.2d at 862. However, as discussed supra,

the Legislature acted swiftly to overrule Leggett by amending West Virginia Code section

22-6-8(e) to require that the royalty payable to the lessee on a flat-rate lease be “not less

than one eighth of the gross proceeds, free from any deductions for post-production

23 At the outset, we reject Mr. Kaess’ argument that this issue has already been determined in Wellman, Estate of Tawney, and Kellam. Although our precedents certainly inform the analysis herein, the syllabus points in the cases specifically apply to leases containing proceeds royalty provisions. 24 Most of the respondent’s arguments on this issue hinge on its contention, which we do not accept, that there is no implied duty to market in an in-kind royalty provision. 26 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.” Id. Indeed,

the flat-rate leases which the Leggett majority found to be unobjectionable in that they

were “freely negotiated contracts” wherein allocated costs and implied covenants were

simply “not within the contemplation of the parties,”25 were characterized by the

Legislature as a

continued exploitation of the natural resources of this state in exchange for such wholly inadequate compensation [which] is unfair, oppressive, works an unjust hardship on the owners of the oil and gas in place, and unreasonably deprives the economy of the State of West Virginia of the just benefit of the natural wealth of this state[.]

Id. § 22-6-8(a)(2). In light of BB Land’s concession in its brief that flat-rate royalty

provisions are similar to in-kind royalty provisions in that the parties “did not contemplate

that the lessee would have the oil or gas in its possession after it was produced from the

ground,” we find the Legislature’s extension of Wellman and Tawney to leases containing

flat-rate royalty provisions to be a persuasive indicator that those precedents should govern

leases containing in-kind royalty provisions as well.

BB Land points out that courts in several other states have held that because

the value of oil or gas in an in-kind royalty provision is its value at or near the wellhead,

25 See Leggett, 239 W. Va. at 276, 800 S.E.2d at 862. 27 where the mineral owner would take possession of his or her share, the producer “satisfies

its obligation to deliver [the lessor’s] share of production ‘free of cost in the pipe line’ by

accounting for [the lessor’s] fractional share on a net-proceeds basis that deducts from

gross sales proceeds the postproduction costs incurred after delivery in the gas gathering

system on the wellsite premises.” Nettye Engler Energy, LP v. BlueStone Nat. Res. II, LLC,

639 S.W.3d 682, 696 (Tex. 2022); see also Vedder Petroleum Corp. v. Lambert Lands Co.,

122 P.2d 600, 604-05 (Cal. 1942) (“There is nothing . . . in the lease itself to justify the

conclusion that there was any duty on the part of the lessee to bear the expense of

dehydrating appellant lessor’s royalty share of the oil produced from wells on the premises,

and, if the duty to clean the oil is absent when the royalty oil is delivered in kind, it is also

absent when the proportionate share of the value of such royalty oil is to be paid in cash.”).

We find the cited authorities to be clearly distinguishable, as the courts’

reasoning is premised on an assumption that the language “at the well” or “at the wellhead”

has a clear, fixed meaning in the context of an oil and gas lease. In contrast, this Court

specifically held in Estate of Tawney that “at the well,” “at the wellhead,” and similar

language, is “ambiguous and accordingly . . . not effective to permit the lessee to deduct

from the lessor’s 1/8 royalty any portion of the costs incurred between the wellhead and

the point of sale.” Est. of Tawney, 219 W. Va. at 268, 633 S.E.2d at 24, Syl. Pt. 11, in part.

Further, as detailed supra, the reasoning in the cited cases is not supported by the common

law of this State, by our precedents upon which thousands of West Virginians have relied

for decades, or by our Legislature, which extended the holdings of Wellman and Tawney

28 to apply to flat-rate leases – leases which by their terms entitle the lessors to a fixed amount

per well, per year, not to any royalties based on value and/or sale price of the oil and gas.

Additionally, the cited cases are wholly inconsistent with the public policy of West

Virginia as articulated by the Legislature: to provide fair and just compensation to mineral

owners and to ensure that West Virginia’s economy is not deprived “of the just benefit of

the natural wealth of this state.” W. Va. Code § 22-6-8(a)(2).

Accordingly, we answer the district court’s second certified question in the

affirmative and hold that if, for whatever reason, the mineral owner/lessor of an in-kind oil

and gas lease containing an in-kind royalty provision does not take his or her percentage

share of the oil and gas in kind, and the producer/lessee elects to market and sell the lessor’s

share of the production on the lessor’s behalf, along with the lessee’s own share of the

production, then, except as may be specifically provided by the parties’ agreement, the

lessee shall tender to the lessor a royalty consisting of the lessor’s percentage share of the

gross proceeds, free from any deductions for postproduction 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.

IV. Conclusion

Based upon our analysis, we answer the certified questions as follows:

29 Question No. 1: Is there an implied duty to market for [oil and gas] leases containing

an in-kind royalty provision?

Answer: Yes.

Question No. 2: Do the requirements for the deductions of post-production

expenses from Wellman v. Energy Resources, Inc., [210 W. Va. 200, 557 S.E.2d 254

(2001)] and Estate of Tawney v. Columbia Natural Resources, [219 W. Va. 266, 633 S.E.2d

22 (2006)], apply to leases containing an in-kind royalty provision?

Certified Questions Answered.