Court Opinion

ID: 7797685
Source: CourtListenerOpinion
Date Created: 2022-08-04 00:00:37.852888+00
Date Added: 2024-06-11T16:28:40.714285
License: Public Domain

Case: 21-10373      Document: 00516418032          Page: 1    Date Filed: 08/03/2022

            United States Court of Appeals
                 for the Fifth Circuit                                 United States Court of Appeals
                                                                                Fifth Circuit

                                                                              FILED
                                                                         August 3, 2022
                                    No. 21-10373
                                                                         Lyle W. Cayce
                                                                              Clerk
   Exxon Mobil Corporation,

                                             Plaintiff—Appellant/Cross-Appellee,

                                       versus

   United States of America,

                                           Defendant—Appellee/Cross-Appellant.

                   Appeal from the United States District Court
                       for the Northern District of Texas
                            USDC No. 3:16-CV-2921

   Before Clement, Graves, and Costa, Circuit Judges.
   Gregg Costa, Circuit Judge:
          In this tax doubleheader, Exxon seeks $1.5 billion from the IRS. The
   source of this whopping sum is two retroactive changes Exxon made to its
   returns. The first change involves a tax issue almost as old as the oil industry
   itself: whether a transaction is a mineral lease or mineral sale. See, e.g.,
   Goldfield Consol. Mines Co. v. Scott, 247 U.S. 126 (1918); Stratton’s Indep.,
   Ltd. v. Howbert, 231 U.S. 399 (1913). The second concerns a more recent
   development in the tax code: how an incentive for producing renewable fuels
   affects a company’s excise tax, and in turn, its income tax. The district court
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   rejected both changes but gave Exxon back a penalty the IRS imposed for
   requesting an excessive refund. We affirm.
                                         I
          The first issue—worth a billion dollars—involves agreements Exxon
   entered into with Qatar and Malaysia to commodify those countries’
   abundant offshore oil-and-gas deposits. The question is whether these
   agreements are mineral leases or mineral sales.
                                         A
                                         1
          The Qatari agreements grant Exxon rights to explore the North Field,
   a large offshore gas field within Qatar’s territorial waters. The agreements
   last for fixed terms, typically twenty years. In exchange for mineral rights,
   Exxon must extract gas and pay Qatar royalties based on the petroleum
   products it produces. These royalties include a percentage of the proceeds
   from the sale of petroleum products as well as a minimum amount based on
   how much gas Exxon brings through its facilities.
          Exxon also must build and operate facilities to transport, store,
   process, and market its products. According to Exxon, it has invested $20
   billion in such infrastructure, which includes a pipeline network to bring the
   offshore gas onshore, liquification facilities to turn the gas into liquid
   products for transportation, and technologically advanced ships that
   transport gas to foreign countries. By some measures, this infrastructure
   produces petroleum products that are twenty times as valuable as gas in
   place. When the agreements end, Qatar keeps this infrastructure. The
   agreements aim to develop an international market for Qatari gas.

                                         2
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             Malaysia sought to create a domestic market for oil and gas. So its
   state-owned oil company 1 entered into similar fixed-term agreements with
   Exxon. The Malaysian agreements give Exxon rights to extract offshore
   minerals in the Malay Basin. In exchange, Malaysia is entitled to in-kind
   royalties—that is, set percentages of the oil extracted from the Malay
   Basin—and additional payments that turn on how much oil is produced. In
   addition, Exxon must make annual “abandonment cess” payments that do
   not depend on mineral production. These payments fund the costs of
   plugging wells at the end of their useful lives. As in Qatar, Exxon has
   developed considerable extraction, transportation, storage, and processing
   infrastructure in Malaysia, which reverts to the state after the contracts
   expire.
                                                  2
             Transfers of mineral interests are typically categorized as leases or
   sales. In a mineral lease, the transferor provides minerals in place and grants
   the transferee the right to explore those minerals in exchange for a share of
   the income from mineral production. See 5 Mertens Law of Federal
   Income Taxation § 24:21 (2022). An example would be allowing
   someone to drill for oil on one’s land in exchange for a 1/4 interest in the oil
   produced. See Murphy Oil Co. v. Burnet, 287 U.S. 299, 300 (1932). In a
   mineral sale, the transferor “makes an outright transfer” of mineral interests
   for fixed consideration that does not depend on mineral production.
   5 Mertens, supra, at § 24:16. An example would be selling a fixed amount
   of minerals under one’s land for $200,000. See Whitehead v. United States,
   555 F.2d 1290, 1292 (5th Cir. 1977).

             1
                 That company is Petronas. This opinion refers to Petronas as Malaysia.

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          Mineral leases and mineral sales receive different income-tax
   treatment. With mineral leases, the transferor’s income from minerals is
   treated as ordinary taxable income. 5 Mertens, supra, at § 24:66. That is,
   a portion of the overall income from minerals is included only in the
   transferor’s taxable income and excluded from the transferee’s taxable
   income. Id. The transferor and transferee are each entitled to depletion
   deductions to the extent of their interest in the minerals. See 26 C.F.R.
   § 1.611-1.
          For mineral sales, the transferor realizes income only at the time of
   the sale. 5 Mertens, supra, at § 24:19. Income derived from the extraction
   of minerals is included in the transferee’s taxable income, and only the
   transferee is entitled to depletion deductions. Id. Income that the transferor
   receives from the transaction—the sales price—is taxed as capital gains. Id.
                                         3
          When it filed its tax returns for years 2006 to 2009, Exxon treated its
   mineral transactions with Qatar and Malaysia as leases. Exxon, as the
   transferee, thus did not include in its taxable income the portion of mineral-
   based income that it paid to Qatar and Malaysia as royalties.
          A few years later, Exxon amended its returns and filed a refund claim.
   In the amended returns, Exxon instead treated the mineral transactions as
   sales. Exxon’s taxable income increased because it now included all the
   income derived from minerals, including the royalties paid to Qatar and
   Malaysia. The income that would have been taxable to Qatar and Malaysia
   in the mineral-lease context was now taxable to Exxon. In turn, Exxon offset
   a portion of the increase in its taxable income by deducting some of the
   royalty payments it made to Qatar and Malaysia.
          Despite the increase in its taxable income, Exxon nevertheless
   requested a massive refund of $1 billion. How so? Exxon’s new math had

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   the downstream effect of clearing the way for it to claim foreign-tax credits.
   Because Exxon had paid foreign tax on the money that it now included in its
   U.S. taxable income, Exxon was able to claim credit intended to prevent the
   double taxation of income. The foreign-tax credits generated its mammoth
   refund request.
            The IRS rejected Exxon’s refund claim. It also imposed a $200
   million penalty for Exxon’s claiming an excessive refund without a
   reasonable basis. Exxon paid the penalty and filed a refund action in district
   court.
            After a bench trial, the district court ruled in the government’s favor
   on the lease-versus-sale issue. On the penalty issue, however, the court held
   for Exxon and ordered a refund. Exxon appealed the lease-versus-sale issue,
   and the government cross-appealed the rejection of the penalty.
                                                B
            The lease-or-sale classification turns on the concept of “economic
   interest.” 2 If Qatar and Malaysia retain an economic interest in the mineral
   deposits that Exxon extracts, the agreements are leases; if not, the
   agreements are sales. Whitehead, 555 F.2d at 1292; see also 5 Mertens,
   supra, at § 24:16. 3

            2
            The district court looked to the “predominant or primary purpose” of the
   agreements to conclude that they are leases. We agree with Exxon and the government
   that our cases do not support that “predominant purpose” analysis. The correct
   benchmark is the economic-interest test.
            3
             The economic-interest test became a feature of oil-and-gas law after enactment
   of the Tariff Act of 1913. Pub. L. No. 63-16, § 2, 38 Stat. 114, 172. That law recognized the
   exhaustible nature of mineral deposits and introduced a “reasonable allowance for
   depletion” of such assets in calculating taxable income. Id. at 172; see Joseph T. Sneed, The
   Economic Interest—An Expanding Concept, 35 Texas L. Rev. 307, 309 (1957). Courts

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           An “economic interest” is a right to share in the profits and losses of
   a business. One example is owning stock. The stock goes up when the
   company succeeds and down when it struggles. Similarly, it seems apparent
   that a party entitled to a percentage of the profits from any oil extracted has
   an economic interest in the oil. The more oil that is drilled, the more money
   the royalty holder makes. See Anderson v. Helvering, 310 U.S. 404, 409 (1940)
   (“The holder of a royalty interest . . . is deemed to have ‘an economic
   interest’ . . . .”).
           The law crystallizes this lay understanding. To have an economic
   interest in minerals in place, a person must have (1) an investment in the
   minerals and (2) income derived solely from extraction of the minerals. 26
   C.F.R. § 1.611-1(b)(1) (adopting the two-part test from Palmer v. Bender, 287
   U.S. 551, 557 (1933)).
           Qatar and Malaysia have an economic interest. In exchange for giving
   Exxon valuable rights to drill in the North Field and Malay Basin, Qatar and

   were soon confronted with the question of which party was entitled to lucrative depletion
   deductions in multiparty transactions. Thus emerged the economic-interest test—
   taxpayers involved in complex oil-and-gas contracts could only claim a depletion deduction
   to the extent of their “economic interest” in the minerals in place. See J. Paul Jackson,
   Federal Income Tax Problems Involved in Typical Oil and Gas Transactions in Texas, 25
   Texas L. Rev. 343, 344 n.4 (1947).
            The typical economic-interest case thus involves taxpayers’ claiming an economic
   interest in a mineral deposit because they want a depletion deduction that will reduce their
   income tax. See, e.g., Comm’r v. Sw. Expl. Co., 350 U.S. 308, 313 (1956). And as alluded to
   above, in some cases taxpayers disclaim an economic interest because doing so means that
   their income from a transaction is taxed favorably as capital gains rather than ordinary
   income. See, e.g., Wood v. United States, 377 F.2d 300, 301 (5th Cir. 1967); 5 Mertens,
   supra, at § 24:15.
           This case distorts those ordinary postures. Here, the focus is not on the taxpayer’s
   (meaning Exxon’s) economic interest, but on that of the counterparty. And Exxon’s
   ultimate goal is not depletion deductions or capital-gains treatment, but downstream
   foreign-tax credit.

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   Malaysia “retain[] a right to share in the [minerals] produced.” Palmer, 287
   U.S. at 557. Qatar receives a percentage of the proceeds from the sale of
   petroleum products and an additional amount that depends on how much gas
   Exxon delivers to its Qatari facilities. Malaysia is entitled to a set percentage
   of oil extracted from the Malay Basin, plus additional payments that turn on
   how much oil and gas is produced.
           These uncapped royalties, which last for the entire duration of the
   agreements, are similar to royalties that case after case deems an economic
   interest. See Palmer, 287 U.S. at 553–59 (holding that a royalty of one-eighth
   of oil produced was sufficient for an economic interest); Rutledge v. United
   States, 428 F.2d 347, 350 (5th Cir. 1970) (holding that royalty payments
   pegged to the amount of material extracted constituted an economic
   interest); Wood, 377 F.2d at 307 (holding that a minimum guaranteed royalty
   payment created an economic interest); Gray v. Comm’r, 183 F.2d 329, 330–
   31 (5th Cir. 1950) (holding that an “overriding royalty of one-fifth of all oil
   produced” and an interest in net profits provided an economic interest).
           Such a durable stream of royalties is the quintessential and indeed
   textbook example of an economic interest. A leading oil-and-gas treatise
   recognizes that a landowner who “leases his land to an oil company in a
   standard oil and gas transaction is considered to have an economic interest
   because of the retained royalty interest.” Owen L. Anderson, John
   S. Dzienkowski, John S. Lowe, Robert J. Peroni, David E.
   Pierce, & Ernest E. Smith, Oil and Gas Law and Taxation
   (A Revision of Hemingway) 464–65 (2017); 4 see also Sneed, supra, at

           4
             Unsurprisingly, five of the six authors of this treatise teach at law schools in
   Texas, four of them at the University of Texas School of Law. And Joseph Sneed, the
   author of a leading article on economic interest who would eventually become a judge on

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   355 (describing an interest “lasting for the productive life of the property”
   and entitling its holder to “beneficial enjoyment of income” as “plainly” an
   economic interest); Leonard Sargeant III, Economic Interest and Depletion
   Allowance for Mining Contractors, 20 Wash. & Lee L. Rev. 322, 330
   (1963) (observing that long-term royalty owners have an economic interest).
           That the retained royalties reflect not only the value of oil and gas at
   the wellhead, but also the significant value that Exxon adds through
   transportation and processing, does not dissolve Qatar’s and Malaysia’s
   economic interest. See Estate of Weinert v. Comm’r, 294 F.2d 750, 764–65
   (5th Cir. 1961) (holding that income from postextraction operations did not
   destroy an economic interest because those operations were “indispensable”
   to the eventual sale of petroleum products). What matters is whether the
   payments depend on minerals. That is why arrangements like minimum
   guaranteed payments, net-profit payments, and advance bonuses also result
   in an economic interest. See Wood, 377 F.2d at 307 (stating that “minimum
   guaranteed royalty provisions” do not “render payment dependent upon a
   factor other than extraction or production”); Kirby Petrol. Co. v. Comm’r, 326
   U.S. 599, 604 (1946) (explaining that an “economic interest in the oil is no
   less when [the] right is to share a net profit” because the “only source of
   payment” is the oil); Burnet v. Harmel, 287 U.S. 103, 111 (1932) (holding that
   bonuses and royalties are not treated differently in the economic-interest
   analysis). Although none of these configurations involve the long-term
   royalty streams that typify an economic interest, in each the sole source of
   return is minerals. Qatar’s and Malaysia’s running royalties, which likewise

   the Ninth Circuit, also had deep ties to Texas’s flagship university, first as a law student
   and later as a member of the law faculty. See Sneed, supra, at 307 n.a1.

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   rely on mineral production, are closer to the classic mineral lease than these
   other examples. 5
           Exxon acknowledges that it has found no case (nor have we) holding
   that a party with an unlimited royalty stream lacks an economic interest in
   the minerals it will still profit from. It instead points to a subset of lease/sale
   cases in which the transferor receives not a running royalty but instead a fixed
   sum called a production payment.
           Production payments are not traditional royalties. Unlike running
   royalties, which “extend to the entire oil and gas resource content of the
   land,” production payments provide a “right to income for a limited time or
   amount.” Caldwell v. Campbell, 218 F.2d 567, 569 n.5 (5th Cir. 1955); see also
   Herbel v. Comm’r, 129 F.3d 788, 790 (5th Cir. 1997) (noting that production
   payments last “shorter than the expected life of the property” (quoting Carr
   Staley, Inc. v. United States, 496 F.2d 1366, 1367 (5th Cir. 1974)));
   Anderson et al., supra, at 641 (noting that production payments are
   twists on traditional royalties and describing them as “limited by a specific
   dollar amount, quantity of mineral extracted, or period of time”). Production
   payments thus do not provide the economic upside of traditional royalties. A
   $5,000 production payment is worth $5,000, no matter whether the drilling
   takes place on a gusher or a dry well. Indeed, the fixed-sum nature of

           5
             To be sure, not everyone who benefits financially from the extraction of minerals
   has an economic interest. Take for example an operator of a gas processing plant who is
   contractually “entitled to a delivery of the gas” produced at certain wells. Helvering v.
   Bankline Oil Co., 303 U.S. 362, 367 (1938). The operator certainly “obtain[s] an economic
   advantage from the production of the gas” through its contracts. Id. at 368. But this
   operator cannot satisfy the first Palmer requirement because it has no capital investment in
   the gas wells. See 287 U.S. at 557. It thus has “no interest in the gas in place.” Bankline,
   303 U.S. at 368. It is a mere contractual beneficiary of the extraction of gas. See also Scofield
   v. La Gloria Oil & Gas Co., 268 F.2d 699, 709 (5th Cir. 1959) (relying on Bankline to arrive
   at a similar holding).

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   production payments is the hallmark of a mineral sale—the transfer of
   mineral interests for a set price. See Whitehead, 555 F.2d at 1292–94; Rhodes
   v. United States, 464 F.2d 1307, 1311 (5th Cir. 1972); 5 Mertens, supra, at
   § 24:17 (exploring the effect of fixed prices). In simple terms, the production
   payment is the sales price. See, e.g., Anderson, 310 U.S. at 413; Christie v.
   United States, 436 F.2d 1216, 1221 (5th Cir. 1971).
          The wrinkle is that production payments, like traditional royalties, can
   reflect income from minerals. See Thomas v. Perkins, 301 U.S. 655, 657–663
   (1937); Herbel, 129 F.3d at 790 (defining a production payment as the “right
   to a specified share or production from a mineral property” (quoting Carr
   Staley, 496 F.2d at 1367)).      Whether production payments leave the
   transferor with an economic interest in the minerals thus requires closer
   scrutiny than the set prices suggest.
          Consider Anderson, 310 U.S. 404. It involved a company’s selling its
   mineral interests for $160,000. Id. at 405. Of that price, $110,000 was
   structured as a production payment.          Id. at 406.   At first blush, this
   transaction resembles a sale because of the fixed sales price. See Helvering v.
   Elbe Oil Land Dev. Co., 303 U.S. 372, 375 (1938). But the production
   payment could have been satisfied with income “derived from oil and gas
   produced.” Anderson, 310 U.S. at 405–06. The potential connection to oil
   and gas made it a closer call whether the transaction depended on mineral
   production. See id. at 410 (noting that an oil payment right “resembles the
   right to cash payments more closely than the right to royalty payments,” but
   recognizing that the payment “depend[s] upon the production of oil”).
          A bright-line rule answers the tricky question of whether production
   payments—which carry set prices but allow mineral extraction to help pay
   them—support an economic interest. When a payment can be satisfied by

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   an alternative, nonmineral source of income, the recipient lacks an economic
   interest because minerals are not the sole source of recovery. See id.
          An alternative source of recovery is why Anderson deemed the
   transaction at issue a sale despite a production payment that could also have
   been satisfied by oil. Id. at 413. The production payment could come from a
   sale of the land itself—a source other than minerals—so the payment did not
   depend on mineral production. Id. at 405–06, 412–13 (explaining that the
   production payment could have alternatively been satisfied “from the sale of
   fee title” to the property). The “reservation of this additional type of
   security” for the production payment dissolved the economic interest. Id.;
   see also Christie, 436 F.2d at 1217, 1221 (holding that a production payment of
   $5,235.24 that could be satisfied by salvage value of equipment precluded
   economic interest); Comm’r v. Estate of Donnell, 417 F.2d 106, 115 (5th Cir.
   1969) (holding that a production payment of $35,275 that was backed by a
   personal guaranty did not create an economic interest); see also 26 C.F.R.
   § 1.636-3 (“A right to mineral in place which can be required to be satisfied
   by other      than the    production of      mineral    from the burdened
   mineral property is not an economic interest in mineral in place.”).
          Only when production payments can be satisfied solely by income
   from minerals do they support an economic interest. Thus, a production
   payment of $395,000 payable solely out of oil resulted in a transferor’s
   retaining an economic interest. Perkins, 301 U.S. at 657–663. The language
   in the cases that a taxpayer has an economic interest only if he looks “solely
   to the extraction of oil or gas for a return of his capital,” Sw. Expl. Co., 350
   U.S. at 314 (emphasis added), reflects this divide between production
   payments backed by alternative sources and those that rely solely on
   minerals.

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          But this discussion of production-payment cases is a detour. See
   Anderson et al., supra, at 465–66 (treating production payments as
   deviations from royalties). This is not a production-payment case because
   Qatar and Malaysia receive no guaranteed price based on Exxon’s mineral
   extraction.
          Exxon nonetheless latches on to the “solely” requirement as applied
   in the production-payment nook of oil-and-gas law and refashions it as a
   magic bullet for the entire edifice. Exxon’s preferred rule is that landowners
   who lease property in exchange for oil royalties have no economic interest if
   they secure other contractual benefits in the same bargain. That would mean
   Qatar and Malaysia lack an economic interest in minerals because they
   receive additional sources of income besides mineral royalties—
   infrastructure, access to markets, and in Malaysia’s case, abandonment cess
   payments.
          Exxon’s view that an economic interest depends on whether a party is
   entitled to oil payments and nothing else misses the mark. The correct
   question is whether a party has a right to any income that depends solely on
   the extraction and sale of minerals. See Kirby, 326 U.S. at 604.
          The “sales” cases that Exxon relies on prove this point. Each found
   no economic interest because the production payment could have been
   satisfied by minerals or nonmineral sources. See Anderson, 310 U.S. at 413;
   Christie, 436 F.2d at 1221; Donnell, 417 F.2d at 115. Those who held the right
   to income had limited downside. They could expect to get paid with or
   without extraction. In contrast, Qatar’s and Malaysia’s right to income
   through royalties depends solely on minerals. Again, without oil and gas,

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   Qatar and Malaysia receive no royalties. That the countries are entitled to
   supplemental income is irrelevant. 6
           Were the rule as Exxon sees it, parties could manipulate the line
   between leases and sales. A lessee who seeks additional depletion deductions
   and a lessor who wants favorable capital-gains treatment could transform
   their lease into a sale by adding unrelated nonmineral payments to their
   agreement. Tax treatment would depend on how many transactions are
   cobbled into one contract. Focusing on the source of individual payment
   obligations like royalties prevents such gamesmanship.                      Supplemental
   sources of income in multifaceted transactions—for example, the
   infrastructure and abandonment cess payments here—receive their own tax
   treatment.
           Exxon argues that Anderson bars our “unworkable” approach of “dis-
   aggregating” its agreements and examining only the source of the royalties.
   This prohibition, in Exxon’s view, comes from Anderson’s directive that
   courts should treat payments “as a whole” rather than “distributively []

           6
             Of course, the “solely” requirement applies in cases not involving production
   payments. See, e.g., Sw. Expl. Co., 350 U.S. at 314. This case would be different if the
   royalties themselves could be satisfied by another source besides petroleum. In that
   scenario, Qatar and Malaysia would have no right to income dependent solely on minerals.
   See Anderson, 310 U.S. at 413 (suggesting that the “reservation in a lease of oil payment
   rights together with a personal guarantee by the lessee that such payments shall at all events
   equal the specified sum[s]” does not constitute an economic interest).
            Exxon argues that the countries’ entitlement to damages for breach of contract fits
   the mold of an alternative source of income. But damages, which by their nature are too
   indefinite and unpredictable to constitute an alternative source, are the standard remedy
   for any breach of contract. If the availability of damages dissolves an economic interest,
   mineral leases would be extinct. See Wood, 377 F.2d at 307 n.19 (explaining that, at least in
   Texas, mineral leases create “an implied covenant to produce”).

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   depending upon the source from which each dollar is derived.” See 310 U.S.
   at 413.
             Exxon misreads Anderson. The rule it quotes means only that tax
   treatment does not depend on whether a production payment is actually paid
   from minerals or an alternative source. If a production payment can be
   satisfied by an alternative source, the transferor has no economic interest. In
   such a case of uncertainty about where the production payment will come
   from, the recipient does not own a stake in the minerals. This is the
   “workable rule” to which Anderson referred. Id.; see also Sneed, supra, at 328
   (advising that the Anderson rule is limited and that “a right to look to mineral
   produced and sold should not be deprived of the economic-interest status
   simply because the holder of such a right is given in the same transaction the
   right to sell personal services to the obligor for a fixed fee”).
             Exxon’s position is irreconcilable with decades of cases recognizing
   that royalties support an economic interest. See supra p.7. Indeed, Anderson
   itself recognizes the basic rule that the “holder of a royalty interest—that is,
   a right to receive a specified percentage of all oil and gas produced during the
   term of the lease—is deemed to have ‘an economic interest.’” 310 U.S. at
   409 (quoting Palmer, 287 U.S. at 557). That rule resolves this case.
             Exxon also cannot explain cases in which we have recognized an
   economic interest despite the presence of both royalties dependent on oil and
   separate sources of income. Weinert, 294 F.2d at 764–65; Gray, 183 F.2d at
   330. The best example is Gray. There, we did not hesitate to hold that a
   taxpayer’s owning royalties along with an interest in a gas processing and
   cycling plant “manifestly resulted in the reservation of an ‘economic
   interest’ in the oil and gas in place.” Gray, 183 F.2d at 331. Just as the
   additional source of income did not eliminate the taxpayer’s economic
   interest in Gray, it does not do so here.

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          Qatar and Malaysia thus have an economic interest in the minerals
   being extracted.     That means the agreements are as Exxon originally
   described them: leases.
                                            C
          That brings us to whether the IRS’s $200 million penalty should
   stand. The IRS can levy a penalty if “a claim for refund . . . is made for an
   excessive amount.” 26 U.S.C. § 6676(a) (2017) (amended 2018). But claims
   with a “reasonable basis” do not warrant a penalty. Id. To satisfy this
   standard, a taxpayer’s position must be “reasonably based on one or more
   of” a number of authorities, 26 C.F.R. § 1.6662-3(b)(3), including caselaw,
   statutes, regulations, private letter rulings, and technical advice memoranda,
   id. § 1.6662-4(d)(3). This standard is relatively high but less stringent than
   other IRS standards like the substantial-authority standard, which requires
   that “the weight of the authorities supporting treatment of an item must be
   substantial in relation to the weight of those supporting contrary treatment.”
   Chemtech Royalty Assocs., L.P. v. United States, 823 F.3d 282, 290 (5th Cir.
   2016). Whether a refund claim has a reasonable basis is reviewed de novo.
   See id. at 287.
          The district court emphasized the complex nature of this case and
   “readily” held that Exxon’s position is reasonably based on legal authority.
   It had to hold a bench trial to resolve the case.
          We see some merit in the government’s view that Exxon did not have
   a reasonable basis for its position. As we have said, no case has ever held that
   a traditional royalty does not leave the transferor with an economic interest
   in the oil from which it can still profit.
          Although Exxon’s position is close to the “reasonable basis” line, we
   end up agreeing with the district court’s assessment. The lease/sale issue is
   a notoriously complex area of tax law. One of our opinions quips that it

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   involves “occult mysteries.” See Donnell, 417 F.2d at 108. And Exxon is not
   the only one to read the “solely” requirement from Anderson and Christie so
   broadly. See Internal Revenue Serv., Tech. Advice Mem.
   199918002, 1999 WL 283075 (Jan. 15, 1999) (loosely reading Anderson and
   Christie as holding that no economic interest exists when “there is a
   possibility of sharing in income not solely derived from extraction”).
   Christie, in which we held that no economic interest existed even though oil
   money ended up satisfying the production payment in whole (because there
   was the possibility the payment could have come from the salvage value of
   the drilling equipment used), is especially susceptible to a broad reading. See
   436 F.2d at 1218.
          The published cases on which the government relies do not require a
   different result. One uses the higher substantial-authority standard. See NPR
   Invs., L.L.C. ex rel. Roach v. United States, 740 F.3d 998, 1013 (5th Cir. 2014).
   And the other is about subjective reliance on relevant legal authorities. See
   Wells Fargo & Co. v. United States, 957 F.3d 840, 854 (8th Cir. 2020).
   Although the penalty question presents a close call, the district court
   correctly granted Exxon a refund on this issue.
                                          II
          Exxon claims that it made yet another mistake in its original tax
   returns. We turn now to that purported blunder. The issue is which amount
   of excise tax Exxon can deduct from its gross income: (1) the lesser amount
   it actually paid after claiming a renewable-fuel credit or (2) the greater
   amount it would have paid without the credit.

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                                         A
                                         1
          Congress levies an excise tax on fuels like gasoline. 26 U.S.C.
   § 4081(a)(1)(A). The tax funds the Highway Trust Fund, which pays for
   America’s highways. 26 U.S.C. § 9503(b)(1).
          Congress tinkers with the excise tax to serve another of its goals—
   encouraging renewable fuels. In years past, Congress has tried to exempt
   renewable gasoline from the excise tax. See Energy Tax Act of 1978, Pub. L.
   No. 95-618, 92 Stat. 3174, 3185. It has also tried to tax renewable gasoline at
   a lower rate than regular gasoline. Highway Improvement Act of 1982, Pub.
   L. No. 97-424, 96 Stat. 2097, 2171.        But these experiments had the
   unintended, though predictable, consequence of depleting the Highway
   Trust Fund.
          The American Jobs Creation Act of 2004 fixed this problem,
   incentivizing renewable fuels while also ensuring the viability of the Highway
   Trust Fund. Pub. L. No. 108-357, § 301, 118 Stat. 1418. The Act repealed
   the reduced excise-tax rate for renewable gasoline. See 118 Stat. at 1461.
   Instead, Congress provided that taxpayers who produced renewable gasoline
   could claim a “credit against” their excise tax. Id. at 1459 (codified at 26
   U.S.C. § 6426(a)). Congress also provided an option for this credit to be
   received by the producer in the form of a direct payment, but only to the
   extent that the credit exceeds the amount allowed against excise tax. Id. at
   1462 (codified at 26 U.S.C. § 6427(e)). And it appropriated money for the
   Highway Trust Fund “without reduction for [the credit.]” Id. (codified at
   26 U.S.C. § 9503(b)(1)). These fixes appropriated the full amount of excise
   taxes to the Highway Trust Fund while also benefitting those who produced
   renewable fuels.

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                                          2
          Paying excise tax reduces income tax. Excise tax paid on fuel is
   deductible from gross income. See 26 U.S.C. § 162; 26 C.F.R. § 1.61-3.
          In tax years 2008 and 2009, Exxon’s original excise-tax liability was
   roughly $6 billion. But Exxon also produced renewable fuels. It was thus
   eligible for a $960 million credit. Exxon applied the credit against its original
   $6 billion liability and paid a reduced excise tax of around $5 billion. On its
   original tax returns, Exxon deducted that lesser amount from its gross income
   rather than the $6 billion-odd it would have owed in excise taxes had it not
   claimed the credit.
          But just as it did with the lease/sale issue, Exxon had a change of
   heart—this one worth $300 million. Exxon filed amended returns that
   deducted $6 billion in excise tax, unreduced by the credit for renewables. In
   other words, Exxon increased its excise-tax deduction, and thus reduced its
   taxable income, by $960 million. That translated to a $300 million reduction
   in tax owed.
          The IRS was not persuaded. It rejected the refund claim, informing
   Exxon that “[s]ince you already used the Credit to reduce the Excise Tax,
   you are not allowed to use the same Credit[] to . . . decrease taxable income.”
   The district court agreed with the IRS.
                                          B
          The statute says that there “shall be allowed” a “credit . . . against”
   the fuel excise tax. 26 U.S.C. § 6426(a)(1). The issue is the meaning of
   “credit.” If the credit reduces excise tax, the taxpayer can deduct only the
   amount of excise tax remaining after subtracting the credit—the amount it
   actually paid. But if, as Exxon contends, the credit satisfies or pays the excise
   tax, it does not alter the amount of tax imposed. And if that is the case, then

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   the taxpayer could deduct the full amount of excise tax imposed without a
   reduction for the credit.
          Exxon is not the only oil company making this argument. Its gambit is
   the latest installment in a series of nearly identical claims that companies have
   filed nationwide. We join the unanimous chorus—judges who comprise two
   courts of appeals and three district courts (9-0 for those keeping score)—to
   hold that Exxon’s credit reduced its excise-tax liability such that it can only
   deduct the excise tax it paid out of pocket. See Delek US Holdings, Inc. v.
   United States, 32 F.4th 495 (6th Cir. 2022); Sunoco, Inc. v. United States, 908
   F.3d 710 (Fed. Cir. 2018); Exxon Mobil Corp. v. United States, No. 3:16-CV-
   2921-N, 2018 WL 4178776 (N.D. Tex. Aug. 8, 2018); Delek US Holdings, Inc.
   v. United States, 515 F. Supp. 3d 812 (M.D. Tenn. 2021); Sunoco, Inc. v.
   United States, 129 Fed. Cl. 322 (2016); see also ETC Sunoco Holdings, LLC v.
   United States, 36 F.4th 646 (5th Cir. 2022) (rejecting Sunoco’s attempts to
   relitigate the case it lost before the Federal Circuit).
          Our analysis begins and ends with the ordinary meaning of “credit.”
   To borrow from the private sector, everyone recognizes that coupons lower
   the cost of goods by reducing sticker prices. Credits do the same thing. As
   we have explained, “[a] tax credit is the public sector equivalent of a coupon;
   it reduces the amount that is otherwise owed.” United States v. Hoffman, 901
   F.3d 523, 538 (5th Cir. 2018) (emphasis added). Dictionaries recognize that
   credits reduce liability. Tax Credit, Black’s Law Dictionary 1501
   (8th ed. 2004) (“An amount subtracted directly from one’s total tax liability,
   dollar for dollar, as opposed to a deduction from gross income.”); Credit,
   Merriam-Webster’s Collegiate Dictionary 294 (11th ed.
   2003) (“[A] deduction from an amount otherwise due.”). Other courts have
   too. See R.H. Donnelley Corp. v. United States, 641 F.3d 70, 74 (4th Cir. 2011)
   (“[T]he Code allows taxpayers to reduce their tax liability dollar-for-dollar
   by claiming credits.”); Telecom*USA, Inc. v. United States, 192 F.3d 1068,

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   1079 (D.C. Cir. 1999) (“[A] tax credit is a dollar-for-dollar reduction in a
   taxpayer’s tax liability.”). Taxpayers who receive the childcare credit would
   no doubt consider the post-credit amount to be their tax liability. It follows
   from this commonly understood meaning of “credit” that when the section
   6426(a) credit is applied against excise tax, it reduces that tax. See Delek, 32
   F.4th at 498 (discerning the ordinary meaning of credit to conclude that the
   credit reduces excise-tax liability); Sunoco, 908 F.3d at 716 (same).
          Exxon and amicus argue that our reading is inconsistent with section
   6427(e), which allows producers to receive the renewable-fuel credit as a tax-
   free direct payment. See 26 U.S.C. § 6427(e)(1). But fuel producers cannot
   claim direct payments in lieu of excise-tax reductions. They must first apply
   the credit against excise-tax liability. See 26 U.S.C. § 6426(a)(1) (stating that
   there “shall be allowed” a credit against excise tax) (emphasis added); Delek,
   32 F.4th at 500–01 (emphasizing that the mandatory term “shall” requires
   taxpayers to first apply the credit against their excise tax). Only if their credit
   exceeds their excise tax can they receive the excess as a direct payment. See
   26 U.S.C. § 6427(e)(3) (“No amount shall be payable . . . with respect to
   which an amount is allowed as a credit under section 6426.”). Indeed, for
   years Exxon applied its credit against its excise tax without first demanding a
   direct payment. Accordingly, our reading does not conflict with section
   6427(e).
          Exxon makes additional arguments, but we agree with the detailed
   reasoning of the Federal and Sixth Circuits rejecting them. See Delek, 32
   F.4th at 499–502; Sunoco, 908 F.3d at 716–17. There is no need to say again
   what has already been said well.
          The text is clear: Exxon’s renewable-fuel credit reduced its excise tax.
   It can deduct only the reduced amount.

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                                     ***
         Exxon was right the first time it filed its returns. We AFFIRM.

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