FILED June 14, 2022 released at 3:00 p.m. EDYTHE NASH GAISER, CLERK SUPREME COURT OF APPEALS OF WEST VIRGINIA
No. 21-0729 – SWN Production Company, LLC and Equinor USA Onshore Properties Inc. v. Charles Kellam, Phyllis Kellam, and all other persons and entities similarly situated
Chief Justice Hutchison, concurring:
I wholeheartedly concur with the majority opinion’s assessment that Estate
of Tawney v. Columbia Natural Resources, L.L.C., 219 W. Va. 266, 633 S.E.2d 22 (2006)
(“Tawney”), and Wellman v. Energy Resources, Inc., 210 W. Va. 200, 557 S.E.2d 254
(2001) (“Wellman”), remain good law in West Virginia. I also agree that the remaining
three questions posed by the district court – essentially asking what language or details are
required by Tawney and Wellman to be included in a lease – are usually case-by-case
questions. Leases are contracts, written repositories of the parties’ intentions. When oil- 1
and-gas leases are not properly drafted or are later interpreted by a party in a slipshod
manner, the questions posed by the district court become issues to be resolved by a court
or factfinder.
I write separately to emphasize the central, general rule underlying Tawney
and Wellman that was only tangentially touched upon by the majority opinion. The rule
underlying Tawney and Wellman is simple: contracts are formed by a meeting of the minds.
You cannot have a meeting of the minds if a contract uses terms that are vague, ambiguous,
“An oil and gas lease (or other mineral lease) is both a conveyance and a 1
contract.” Syl. pt. 1, in part, McCullough Oil, Inc. v. Rezek, 176 W. Va. 638, 346 S.E.2d 788 (1986).
1 and neither understood nor accepted by both parties. This rule is immutable and is, with
few exceptions, the basis for every legally enforceable agreement.
To understand the general rule at the heart of Wellman and Tawney in the
context of an oil and gas lease, the reader must understand other, more specific, long-
standing interwoven guidelines tied to the interpretation of oil and gas leases. These
guidelines are, by default, implied into every oil and gas lease. For over a century, the first
guideline has been that lessee/oil-and-gas companies cannot lease oil and gas rights and
then sit on those rights, to the detriment of the owner/lessor of the rights. Thus, the 2
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. 3 Included in that goal is an
2 See St. Luke’s United Methodist Church v. CNG Dev. Co., 222 W. Va. 185, 191-92, 663 S.E.2d 639, 645-46 (2008) (“This Court has recognized the unfairness of allowing a lessee to effectively tie up land when others stood ready to develop the same.”); Syl. pt. 1, in part, McCullough Oil, Inc. v. Rezek, 176 W. Va. 638, 346 S.E.2d 788 (1986) (An oil and gas lease “is designed to accomplish the main purpose of the owner of the land and of the lessee (or its assignee) as operator of the oil and gas interests: securing production of oil or gas or both in paying quantities, quickly and for as long as production in paying quantities is obtainable.”); United Fuel Gas Co. v. Smith, 93 W. Va. 646, 117 S.E. 900, 904 (1923) (“[T]here is always implied in every oil and gas lease a covenant to drill the number of wells reasonably necessary to develop the property and prevent drainage by operation on adjoining lands.”); Lowther Oil Co. v. Miller-Sibley Oil Co., 53 W. Va. 501, 44 S.E. 433, 435 (1903) (“[A] lease calls for the right, not to oil in place, but to extract it.”); Parish Fork Oil Co. v. Bridgewater Gas Co., 51 W.Va. 583, 42 S.E. 655 (1902) (recognizing as universal the principle of law “which discourages tying up and rendering unproductive the vast fields of mineral wealth, construes every contract and lease as to both lessor and lessee so as to best promote production, development and progress, and frowns upon every attempt to evade it as being in contravention of both good morals and public policy.”).
See generally, Keith B. Hall, Implied Covenants and the Drafting of Oil 3
and Gas Leases, 7 LSU J. Energy L. & Resources 401, 418 (2019) (“The implied covenant 2 understanding that the lessee bears all of the risks and costs of drilling, producing, and
getting the oil and gas to market. Hence, the lessee bears the risk of drilling a dry well.
The lessee also bears the risk that the physical properties of any oil or natural gas
discovered may be of a lesser quality or pressure than is desired.
Another corollary, default guideline implied into every oil and gas lease is
just as clear: the lessor/owner of oil and gas rights is entitled to royalties, that is, a share of
the profit gained from the oil and gas the lessee delivers to market. In West Virginia, those
royalties are, by default, (1) based on the gross proceeds received by the lessee at the first
point of sale to an unaffiliated third-party purchaser in an arm’s length transaction, and (2)
free from any deductions for the expenses incurred by the lessee getting the oil and gas to
market.
Wellman involved another basic doctrine of contract law: the parties to an oil
and gas lease can agree to disclaim any of the default, implied guidelines I just described,
and contract for a different result. Our opinion plainly stated the default guideline, which
is that that every oil and gas lease is built on a presumption that the lessee will bear both
the responsibility and the cost of getting the minerals to an impartial marketplace. We
to market requires a lessee to diligently seek purchasers at a reasonable price for any oil or gas that is found in paying quantities.”); Nancy Saint-Paul, 2 Summers Oil and Gas § 18:11 (3d ed. 2021) (“In order to carry out the purposes for which an oil and gas lease is made, that is, the . . . production and sale [of oil and gas] so as to yield a profit to the lessee and a return to the lessor in the form of rents and royalties, it is necessary that the oil or gas produced from the land be marketed.”).
3 ruled in Wellman that a lease can alter that presumption and provide that the lessor will
bear a share of the costs of getting the oil and gas to market, but only if those costs were
(1) actually incurred by the lessee, and (2) reasonable. Syl. pts. 4 and 5, Wellman, 210 W.
Va. at 202, 557 S.E.2d at 256.
In Tawney, we reiterated and expounded on Wellman. We determined that,
to vitiate the presumption that the lessee bears the costs of getting the minerals to market,
and to shift some share of the costs onto the lessor, the lease between the parties needs to
identify with particularity the specific deductions for post-production marketing costs that
the lessee intends to take from the lessor’s royalties, and it must indicate the method of
calculating those deductions. See Syl. pt. 10, Tawney, 219 W. Va. at 268, 633 S.E.2d at
24. As the majority opinion makes clear, when a lessee seeks to deduct post-production
expenses from the gross proceeds received in the sale of oil or gas to calculate a lessor’s
royalty, Tawney continues to require that the lease expressly provide that the lessor shall
bear some part the costs incurred between the wellhead and the point of sale (that is, the
first sale to an unaffiliated third-party purchaser in an arm’s length transaction); identify
with particularity the specific deductions the lessee intends to take from the lessor’s
royalty; and indicate the method of calculating the amount to be deducted from the royalty
for such post-production costs. Id.
Stated simply, Wellman created accountability in oil and gas leases, by
clearly stating that oil and gas lessees cannot make deductions to royalties for any post-
production costs of marketing unless those costs are (1) clearly shifted onto the lessor in
4 the lease; (2) actually incurred, and (3) reasonable. Syl. pts. 4 and 5, Wellman, 210 W. Va.
at 202, 557 S.E.2d at 256. Tawney created transparency, by requiring oil and gas
companies to explain with particularity in the lease the deductions they intend to take from
the lessor’s royalties, and to state with reasonable precision how those deductions will be
calculated. Syl. pt. 10, Tawney, 219 W. Va. at 268, 633 S.E.2d at 24. Together, the cases
are the foundation of what legal scholars call the “marketable-product rule,” because they
explain the default position, in every lease, that oil and gas companies bear the cost of
preparing and shipping the product they’ve taken out of the lessor’s ground to market.
Only if the parties plainly and unambiguously agree to something different will the
lessee/company be permitted to shift some of those “post-production” costs onto the lessor.
After this Court issued Tawney and Wellman, and several other state courts
adopted the marketable-product rule as well, a few legal commentators offered criticism.
One said that the cases were schemes “to provide the lessor with a larger piece of the gas-
production pie.” Another said the cases were written in a way that “results in an even 4
bigger windfall for lessors.” One oil and gas lawyer called the marketable-product rule 5
nothing more than “a massive shifting of post-production costs from lessors to lessees,”
and “a judicially directed wealth transfer from lessees to lessors that contradicts the
4 David E. Pierce, Royalty Jurisprudence: A Tale of Two States, 49 Washburn L.J. 347, 369 (2010).
Brian S. Wheeler, Deducting Post-Production Costs When Calculating 5
Royalty: What Does the Lease Provide?, 8 Appalachian J.L. 1, 27 (2008).
5 bargained-for exchange struck by the parties.” Essentially, these commentators cast this 6
Court’s efforts as some modern-day, wealth-redistribution scheme to rewrite oil and gas
leases to take money from the lessee and give it to the lessor.
These critiques are biased nonsense. First, the marketable-product rule is not
a “modern-day” concept, rather, it dates back over eight decades. Scholarly texts outlined
the boundaries of the rule as early as 1940, when Professor Maurice Merrill (a well-known
leader in the development oil-and-gas law) said:
If it is the lessee’s obligation to market the product, it seems necessarily to follow that his is the task also to prepare it for market, it if is unmerchantable in its natural form. No part of the costs of marketing or of preparation for sale is chargeable to the lessor.
Maurice H. Merrill, The Law Relating to Covenants Implied in Oil and Gas Leases § 85,
at 214-15 (2d ed. 1940). Another titan of oil and gas law, Professor Eugene Kuntz,
advocated for the marketable-product rule as early as 1962:
[T]here is a distinction between acts which constitute production and acts which constitute processing or refining of the substance extracted by production. Unquestionably, under most leases, the lessee must bear all costs of production . . . It is submitted that the acts which constitute production have not ceased until a marketable product has been obtained.
Eugene Kuntz, A Treatise on the Law of Oil and Gas § 40.5 (1962). See also, Owen L.
Anderson, Royalty Valuation: Should Royalty Obligations Be Determined Intrinsically,
6 John W. Broomes, Waste Not, Want Not: The Marketable Product Rule Violates Public Policy Against Waste of Natural Gas Resources, 63 U. Kan. L. Rev. 149, at 149 and 174 (2014).
6 Theoretically, or Realistically? Part 2, 37 Nat. Resources J. 611 (1997) (“[A]bsent an
express lease provision to the contrary, lessees should not have to pay royalty on any value
added to production by reason of incurred ‘post-production’ activities. However,
‘production’ should not be regarded as having been completed until a first-marketable
product has been obtained.”).
Second, most critics of the marketable-product rule inherently, but wrongly,
assume that the production of oil and gas is a shared adventure by a lessor and a lessee.
But the facts usually show that lessor/land-and-mineral owners and lessee/oil-and-gas
companies are not partners on anything close to resembling an equal footing. The
imbalance in the relationship between lessor and lessee is most obvious in the take-home
profits. That is, in most leases, the lessor only receives a small percentage of the final
profit in the form of rents and royalties (usually 1/8) while the lessee oil-and-gas company
retains much more (usually 7/8 of the gross profit).
But the differences between the parties to a lease go far deeper. In this case
the parties are arguing over whether the lessor should pay a share of the “charges” incurred
by the lessee for compressing, dehydrating, and transporting oil, gas, or coalbed methane.
The lease gives the lessee exclusive control over whether, when, and how to incur those
charges, and the lessor has no input. The lessor does not choose the method used for
compression, dehydration, or transportation. The lessor does not choose whether, when,
or how much to spend when a new building, warehouse, office, or compression station is
constructed. These physical structures can be depreciated or written off of the lessee-
7 owner’s taxes, but the lessor does not share the benefit of those tax write-offs. Moreover,
at some point, those physical assets may be divested or leased-out by the lessee/oil-and-
gas company for a profit which is not shared with the lessor. The lessee may buy equipment
like a pickup truck to improve operations; the purchase of the truck is a post-production
“charge” that the lessee might insist be shared by the lessor/land-or-mineral owner, and its
use to travel to a lunch destination or an industry convention an operational “charge,” but
the sale of the truck would just be a “profit” or return of capital to the lessee alone. Put
simply, the lessors of minerals are not equal partners with the lessees.
Further, as I noted earlier, critics of the marketable-product rule proffer that
it creates a “windfall” for mineral-rights owners. These owners sign a lease expecting a
royalty calculated as a percentage of the market price received by the lessee. The Merriam-
Webster Dictionary defines a “windfall” as “an unexpected, unearned, or sudden gain or
advantage.” I am bewildered when critics construe paying a mineral-rights owner their
rightful rent or royalty as an unexpected, unearned gain. Restaurants and other businesses
often pay their landlords rent based on a percentage of the business’s gross sales; no one
ever complains when a landlord gains higher rents after the restaurant or business hired
more people, bought more equipment or stock, did more business, and earned more profits. 7
Douglas Hale Gross, Calculation of rental under commercial percentage 7
lease, 58 A.L.R.3d 384, § 2 (1974) (“Percentage leases of commercial retail premises, having originally been employed many years ago, are by now widely used. Between 1910 and 1925, percentage leases were coming into increasing use, just as they are today, in situations where a landowning lessor improved his premises with a building erected to meet the specifications of potential business lessees; the lessor could borrow on the strength of potential percentage rent payments plus minimum rental obligations of the lessee. While 8 When a lessee obtains a higher market price for the oil and gas it took from the lessor by
dehydrating, compressing, and transporting the mineral, the lessee pockets a higher profit.
Yet, somehow, if the mineral owner receives their contractually set percentage share of
those higher profits as a royalty, critics declare that to be an unfair windfall. The
disingenuousness of this position is stinging.
The royalties due to mineral owners/lessors stay the same under the
marketable-product rule (usually 1/8); they never receive a larger piece of the gas-
production pie, and there is no judicially directed wealth transfer. In the perpetually
unequal oil-and-gas relationship, the owners of minerals allow lessees to extract those
minerals from the ground in exchange for a share of the market price. That share stays the
same whether the market price rises or drops. Of course, no owner of mineral rights signs
a lease anticipating the term “market price” will be an opportunity for gamesmanship;
market price means the price garnered in a sale to an unaffiliated third-party purchaser in
an arm’s length transaction. “The lessee’s duty of good faith and fair dealing would require
that the first market be real, existing, and substantial, and not a market created in bad faith
to limit the royalty obligation” Anderson, 37 Nat. Resources J. at 686-87. What the lessee
choses to do to those minerals to increase the market price is solely within the lessee’s
discretion and control. Accordingly, the lessee bears the full burden of the costs incurred
at first percentage leases were used primarily to lease valuable downtown retail locations, today they are used in neighborhood and shopping center store leases as well.”).
9 getting the mineral to market, unless the parties’ lease clearly and unambiguously specifies
otherwise.
A third problem I see with critics of Wellman, Tawney, and the marketable-
product rule is their refusal to recognize that it is, for all intents and purposes, the majority
rule in America. “A large group of jurisdictions – a group that accounts for far more than
half of the nation’s oil and gas production – follows a marketable-condition rule that
requires the lessee to bear the cost of putting oil and natural gas into a marketable
condition.” John Burritt McArthur, Oil and Gas Implied Covenants for the Twenty-First
Century, 237 (2014). At least five jurisdictions have adopted a variation of the marketable-
product doctrine by appellate court decision: Arkansas, Colorado, Kansas, Oklahoma, 8 9 10 11
8 Hanna Oil & Gas Co. v. Taylor, 759 S.W.2d 563, 565 (Ark. 1988) (holding that the lessee was “not entitled to deduct compression costs” when the lease based royalties on “the proceeds received by Lessee”). 9 Garman v. Conoco, Inc., 886 P.2d 652, 659 (Colo. 1994) (“In our view the implied covenant to market obligates the lessee to incur those post-production costs necessary to place gas in a condition acceptable for market. Overriding royalty interest owners are not obligated to share in these costs.”).
Sternberger v. Marathon Oil Co., 894 P.2d 788, 799 (Kan. 1995) (“The 10
lessee has the duty to produce a marketable product, and the lessee alone bears the expense in making the product marketable.”).
Wood v. TXO Production Corp., 854 P.2d 880, 882 (Okla. 1992) (“In our 11
view, the implied duty to market means a duty to get the product to the place of sale in marketable form.”); TXO Production Corp. v. State ex rel. Commissioners of the Land Office, 903 P.2d 259, 262 (Okla. 1994) (“Clearly, under Wood, [the lessors] were not chargeable with a portion of the costs of compression because such costs are borne by the lessee under its duty to obtain a marketable product. . . . If the processes of dehydration 10 and West Virginia. Critics often complain that these decisions espouse varying 12
interpretations of the doctrine, without recognizing that the common law of each state
differs, and the leases and facts of each case differ wildly as well. Additionally, at least 13
three states have adopted the rule and banned the deduction of post-production marketing
costs by statute. Importantly, the marketable-product rule has been adopted by the largest 14
owner of mineral interests in the country: the United States government. Federal
regulations provide that, for leases on federal land, any gas produced must be marketed “at
no cost to the Federal government.” 15
and gathering are necessary to prepare the product for market, then the costs of these processes may not be deducted under the royalty provision of the subject lease.”).
One scholar suggests that while a comparable number of states have 12
adopted wildly different versions of the “at the wellhead” doctrine, those states’ decisions are often contradictory or conflict with decisions that suggest the states might actually follow some form of the marketable-product rule. See, e.g., John Burritt McArthur, Some Advice on Bice, North Dakota’s Marketable-Product Decision, 90 N. D. L. Rev. 545, 549- 563 (2014). 13 Appellate judges are not monks studying law in ivory towers and deriving perfect legal principles from the ether. The written opinions of appellate courts are a direct extension of the quality of the briefing and advocacy presented by the parties, both to the appellate courts and to the trial courts below.
States adopting marketable-product rules by statute include Michigan 14
(Mich. Comp. Laws § 324.6503b(1) (1999)); Nevada (Nev. Rev. Stat. § 522.115 (2000)); and Wyoming (Wyo. Stat. Ann. § 30-5-304(iv) (1999)).
30 C.F.R. § 1206.146(a) provides that a lessee “must place gas, residue gas, 15
and gas plant products in marketable condition and market the gas, residue gas, and gas plant products for the mutual benefit of the lessee and the lessor at no cost to the Federal government.” See also 30 C.F.R. § 206.152(i) (2010) (“The lessee must place gas in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Federal Government.”); Thomas F. Reese & Drake D. Hill, Wyoming’s 11 Moreover, the Legislative and Executive branches of West Virginia have
adopted the marketable-product doctrine. Regarding the Legislature, as the majority
opinion notes, in Leggett v. EQT Production Company, 239 W. Va. 264, 800 S.E.2d 850
(2017), this Court refused to extend the Wellman and Tawney marketable-product doctrine
to “flat-rate” leases governed by state law. Within a year, the Legislature overruled
Leggett, amended state law, and provided that 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 § 22-6-8 (2018).
As to the Executive branch, it too hews to the marketable-product rule for
leases of oil and gas on State lands. The State’s leases expressly provide that a lessee may
not deduct the cost of putting oil and natural gas into a marketable condition from royalties
due to the State of West Virginia:
Production & Post-Production Costs. Neither Lessee, nor any Affiliate of Lessee, may reduce Lessor’s royalty for any post- production expense, including, but not limited to, pipelines, surface facilities, telemetry, gathering, dehydration, transportation, fractionation, compression manufacturing, processing, treating, or marketing of the Granted Minerals, or any severance or other taxes of any nature paid on the production thereof. Royalties under this Lease shall be based
Powder River Basin: A Study in Federal Royalty Valuation, 4 Wyo. L. Rev. 629, 630 (2004) (discussing royalty calculation issues on production from leases on federal lands).
12 on the total proceeds of sale of the Granted Minerals, exclusive of any and all production and/or post-production costs. 16
Hence, it is a far stretch for any litigant to insist that this Court adopt a rule wholly at odds
with the policies adopted by the Legislature and Executive.
Fourth and finally, I feel compelled to discuss a case that was not addressed
by the majority opinion: Young v. Equinor USA Onshore Properties, Inc., 982 F.3d 201
(4th Cir. 2020). The Young court was asked on appeal to review a complicated “work-
back” method used by an oil-and-gas lessee to make deductions to a lessor’s royalty
payment. The district court had found the lease language describing the deductions to be
insufficient because it “‘merely state[d] that the lessee will deduct post-production costs,’
yet ‘[said] absolutely nothing as to how those costs would be calculated, other than to leave
the amount of the deduction wholly to the lessee’s discretion.’” Id. at 207-08. On appeal,
the Young court relied upon the now-defunct analysis used by this Court in Leggett to
reverse the district court and approve the lease’s language. The Young court rejected any
notion that a lease should have a clear, mathematical formula to calculate how deductions
will be taken:
Tawney doesn’t demand that an oil and gas lease set out an Einsteinian proof for calculating post-production costs. By its plain language, the case merely requires that an oil and gas lease that expressly allocates some post-production costs to the
See West Virginia Department of Commerce, Mineral Development 16
Properties, executed lease agreement between the State of West Virginia and SWN Production Company, underlying portion of the Ohio River within MM60 to southern end of MM70, being approximately 320.44 acres, at https://wvmineraldevelopment.org/ mineral-development-properties (last visited June 14, 2022).
13 lessor identify which costs and how much of those costs will be deducted from the lessor’s royalties. These conditions may be satisfied by a simple formula[.]
Id. at 208 (emphasis in original).
I question the Young court’s statement that Tawney only requires a lease to
contain a “simple formula” and not “an Einsteinian proof” describing how a lessee’s post-
production costs of getting oil and gas to market will be deducted from a lessor’s royalty.
This statement is correct only if the oil-and-gas lessee is actually taking simple, clear, and
unambiguous deductions from the royalties. The problem that I see demonstrated by the
case law is that oil-and-gas lessees insist on taking estimated costs or vague, malleable,
impossible-to-measure deductions from royalties – in essence, using Einsteinian methods
that are incomprehensible to all but the most clever industry accountants. Lessees are using
accounting-based chicanery and devising deductions designed to completely consume the
lessor’s royalty through a “death by a thousand cuts” strategy. 17 See generally, Adam H.
Wilson, Without A Leggett to Stand on: Arguing for Retroactive Application of West
Virginia’s Amended Flat-Rate Well Statute, 124 W. Va. L. Rev. 259, 282 (2021) (“At first
blush, the net-back method may sound like an equitable way to allocate costs between
lessor and lessee; however, lessees use the net-back method to fleece lessors of their
valuable minerals. Gas companies . . . best effectuate this by creating wholly-owned
See Amicus Curiae Brief on Behalf of West Virginia Royalty Owners’ 17
Association, West Virginia Farm Bureau, Bounty Minerals LLC, and Siltstone Resources, LLC (in Support of Respondents Charles Kellam, et al.) at 17.
14 subsidiary companies that charge the mineral owner with what would be otherwise
impermissible deductions.”). Frankly, if the lease does not contain a clear explanation of
any and all deductions or how those deductions are calculated, understandable by both the
oil-and-gas lessee and the mineral owning lessor, then no contract has been formed and the
deductions cannot be taken.
The rules of contract formation are taught in the first weeks of law school.
“It is elementary that mutuality of assent is an essential element of all contracts.” Bailey
v. Sewell Coal Co., 190 W. Va. 138, 140, 437 S.E.2d 448, 450 (1993). For this mutuality
to exist, “it is necessary that there be a proposal or offer on the part of one party and an
acceptance on the part of the other.” Id. “The contractual concept of ‘meeting of the
minds’ or ‘mutual assent’ relates to the parties having the same understanding of the terms
of the agreement reached.” Messer v. Huntington Anesthesia Grp., Inc., 222 W. Va. 410,
418, 664 S.E.2d 751, 759 (2008).
For an oil-and-gas lease to be an enforceable contract, there must be
mutuality of assent. Both parties must have the same understanding of the terms of their
agreement. Yet leases wrongfully continue to be drafted with ambiguous definitions of the
post-production marketing expenses the oil-and-gas lessee intends to deduct from the
lessor’s royalties. Moreover, lessees deduct estimates of expenses, or make other vaguely
characterized deductions, from royalties without clearly explaining how those deductions
are within the terms of the lease. If lessees would simply follow Wellman and Tawney,
there would be far less uncertainty in lessor-lessee relations and, concomitantly, less
15 litigation. The details of deductions should be discussed and agreed-upon when the lease
is negotiated and signed; when they are not, or the lessee gives the lease terms a new
interpretation beyond that discussed by the parties, then litigation over the lease is sure to
follow.
Accordingly, I respectfully concur with the majority’s opinion.