Section 1.871–15(p) generally provides that a broker or dealer is responsible for determining whether a potential section 871(m) transaction is a section 871(m) transaction and for reporting to the customer the timing and amount of any dividend equivalent. Section 1.871–15(a)(1) defines the term broker as “a broker within the meaning provided in section 6045(c).” Comments explained that many regulated investment companies satisfy the definition of a broker under section 6045(c) and the regulations thereunder because the term broker includes a corporation that regularly redeems its own shares. The comments noted that these regulated investment companies may enter into transactions as a short party with a foreign financial institution who is the long party. In these transactions, the comments asserted, the foreign financial institution (not the regulated investment company) is more capable of determining delta and making other calculations.

The Treasury Department and the IRS agree that an entity should not be treated as a broker for purposes of section 871(m) solely because it redeems its own shares. The rules are intended to assign responsibility for making the determinations related to potential section 871(m) transactions to the party that regularly enters into equity derivatives with customers or holds equity derivatives on behalf of customers. When a regulated investment company is the short party in a transaction with a financial institution, the Treasury Department and the IRS agree that the financial institution is in the better position to determine delta and make other determinations required by section 871(m). Accordingly, the definition of the term broker has been revised in the temporary regulations so that it will not apply to a corporation that would be treated as a broker pursuant to section 6045(c) solely because it regularly redeems its own shares.

Section 1.871–15(c) provides that, subject to certain exceptions, a dividend equivalent includes any payment that references the payment of a dividend from an underlying security pursuant to a securities lending or sale-repurchase transaction, specified NPC, or specified ELI. A dividend is defined in § 1.871–15(a)(3) as “a dividend as described in section 316.” Section 1.871–15(c)(2)(ii) reduces a dividend equivalent by any amount treated in accordance with sections 305(b) and (c) as a dividend (a “section 305(c) dividend”) with respect to the underlying security referenced by the section 871(m) transaction.

A comment suggested that the regulations clarify how this rule applies when a derivative references an underlying security that has a section 305(c) dividend. Another comment noted that § 1.871–15(c)(2)(ii) reduces the dividend equivalent amount by section 305(c) dividends, and that this reduction arguably applies both to the person who holds the underlying security giving rise to the section 305(c) dividend and to a holder of a section 871(m) transaction that references the underlying security that gives rise to the section 305(c) dividend.

To address these comments, these final regulations revise the definition of a dividend to explicitly provide that it applies without regard to whether there is an actual distribution of cash or property. A conforming change is also made to § 1.871–15(c)(2)(ii), which is revised to clarify that only a long party that is treated as receiving a section 305(c) dividend is entitled to reduce its dividend equivalent amount and that a section 305(c) dividend gives rise to a dividend equivalent.

Thus, for example, a long party that owns a convertible note that is a section 871(m) transaction and has a section 305(c) dividend can reduce its dividend equivalent by the section 305(c) dividend. In contrast, a long party that owns a specified NPC that references the same convertible note would receive a dividend equivalent that includes the section 305(c) dividend and would not be entitled to reduce its dividend equivalent by the section 305(c) dividend on the convertible note because the long party does not own the note, and therefore, is not treated as receiving a section 305(c) dividend for federal income tax purposes.

To be a simple contract as defined in § 1.871–15(a)(14)(i), the number of shares required to calculate the amounts paid or received on any payment determination date must be ascertainable at the time the delta for the transaction is calculated. Several comments noted that transactions may provide for anti-dilution adjustments to the number of shares as a result of certain corporate actions, and that these adjustments could cause contracts that otherwise would be simple contracts subject to the delta test to become complex contracts subject to the more complicated substantial equivalence test. Adjustments that are intended to maintain the status quo of shareholders generally should not preclude a transaction from being treated as a simple contract. Accordingly, a sentence is added to § 1.871–15(a)(14)(i) to provide that an adjustment to the number of shares of the underlying security for a merger, stock split, cash dividend, or similar corporate action that impacts all the holders of the underlying security will not prevent the transaction from being a simple contract.

The exceptions for payments made pursuant to annuity, endowment, and life insurance contracts were issued as a temporary rule in § 1.871–15T(c)(2)(iv) of the 2015 temporary regulations. Comments generally agreed with the result in § 1.871–15T(c)(2)(iv)(A) with respect to insurance contracts issued by domestic insurance companies. Several comments requested that § 1.871–15T(c)(2)(iv)(A) be issued as a final regulation without any change. These comments noted that any U.S. source dividend that a foreign insurer receives on U.S. stock it owns with respect to an annuity, endowment, or life insurance contract is already subject to withholding tax.

Another comment recommended changes to make the exception for insurance issued by a foreign company more administrable. That comment suggested that the regulations be extended to any foreign insurance company, without regard to whether the company is predominantly engaged in the business of insurance and would be subject to tax under subchapter L. This comment also recommended that the regulations define the terms “annuity contract,” “insurance contract,” “life insurance contract,” “endowment contract,” and “foreign insurance company” based on regulations under section 1471. Finally, the comment noted that the requirement that a company be “predominantly engaged in an insurance business” is unnecessary in light of the requirement that a corporation “would be subject to tax under subchapter L if it were a domestic corporation” because a corporation that would be “subject to tax under subchapter L if it were a domestic corporation” necessarily would be “predominantly engaged in an insurance business.”

Comments also recommended that the temporary rule relating to reinsurance should be finalized. Another comment noted that reinsurance subject to the U.S. federal excise tax under section 4371 is not subject to withholding and expressed concern about the interaction of the excise tax and the application of section 871(m) if the reinsurance exception in the temporary regulations was allowed to expire.

These regulations finalize § 1.871–15T(c)(2)(iv) with one change. The Treasury Department and the IRS agree that a company that is taxable under subchapter L as an insurance company is necessarily predominantly engaged in an insurance business. Accordingly, in finalizing § 1.871–15T(c)(2)(iv)(B), the redundant phrase “predominantly engaged in an insurance business “ is removed. Although comments suggested other modifications to certain terms and the addition of certain defined terms, these final regulations do not make these additional changes. The Treasury Department and the IRS have determined that the scope of entities and contracts described in the temporary regulations as eligible for the exception is appropriate for section 871(m), and that it is beyond the scope of these regulations to define terms relating to insurance.

Section 1.871–15(g)(2) provides that the delta of a potential section 871(m) transaction is determined only when the contract is issued. For this purpose, an NPC or ELI is issued at the time of the contract’s inception, original issuance, or issuance as a result of a deemed exchange pursuant to section 1001. See § 1.871–15(a)(6). The same standard is used to determine when a contract is issued for purposes of the substantial equivalence test for complex contracts.

For simple contracts, comments generally suggested changing the time for calculating delta to the earlier of the trade date or the date on which the parties agreed to the material terms or final pricing for the contract. One comment recommended that the date and time when the material terms are finalized is the appropriate date for determining delta because that is the time when the economic terms of the potential section 871(m) transactions are established. Finally, the parties to the contract are generally bound by the terms on the pricing date, not the settlement date. A comment suggested using the trade date if the pricing date is more than 14 days before the issue date because providing too long a period between the pricing and issue date may present an opportunity for abuse.

For listed options, comments suggested a different method for determining the delta of the contract. These comments recommend that the delta for listed options should be based on the closing price from the prior trading day. The comments acknowledged that this approach would be less accurate than the requirement in the final regulations; however, these comments asserted that using the delta calculation from the prior day for listed options would substantially reduce the burden on taxpayers and make the rules more administrable. Comments also noted that the Options Clearing Corporation currently calculates the end-of-day delta for options listed on U.S. options exchanges.

For complex contracts, comments recommended that the substantial equivalence test should be conducted on the date when the short party’s hedge is established. According to the comments, the issuer of a complex contract enters into a hedge on the pricing date, not the settlement date. The pricing date therefore reflects the economics of a complex contract more accurately than the settlement date, as long as the two dates are not separated by too much time.

The Treasury Department and the IRS agree with the comments that the date for determining delta and for performing the substantial equivalence test should be revised to be more administrable and to reflect more accurately the economics of the transactions. Accordingly, these regulations provide that the delta of a simple contract is determined on the earlier of the date that the potential section 871(m) transaction is priced and the date when the potential section 871(m) transaction is issued; however, the issue date must be used to determine the delta if the potential section 871(m) transaction is priced more than 14 calendar days before it is issued. A similar rule also applies to the substantial equivalence test.

In addition, the regulations provide a new rule for determining the delta of an option listed on a regulated exchange. For these options, the delta is determined based on the delta of the option at the close of business on the business day before the date of issuance. For this purpose, the regulations define a regulated exchange. A regulated exchange is any exchange defined in § 1.871–15(l)(3)(vii) or a foreign exchange that (A) is regulated by a government agency in the jurisdiction in which the exchange is located, (B) maintains certain requirements designed to protect investors and to prevent fraud and manipulation, (C) maintains rules to promote active trading of listed options, and (D) had trades for which the notional value exceeded $10 billion per day during the prior calendar year.

The 2015 final regulations provided a simplified delta calculation for certain simple contracts that reference 10 or more underlying securities, provided that the short party uses an exchange-traded security that references substantially all the underlying securities to hedge the NPC or ELI at the time it is issued (the “hedge security”). The simplified delta calculation allows the short party to calculate the delta of the NPC or ELI by reference to changes in the value of the hedge security. Comments suggested that this rule be extended to cases in which the short party could fully hedge its position by acquiring the exchange-traded security even if it does not in fact hedge in this manner. Because the exchange-traded security must provide a full hedge of the NPC or ELI for this rule to apply, the Treasury Department and the IRS agree that the exchange-traded security will provide an acceptable delta calculation whether or not the short party actually uses that security as its hedge. Accordingly, the regulations are amended to permit the delta with respect to those NPCs and ELIs to be calculated by determining the ratio of the change in the fair market value of the simple contract to a small change in the fair market value of an exchanged-traded security when the exchange-traded security would fully hedge the NPC or ELI.

Some comments noted that third-party data, including delta calculations, may be available for certain potential section 871(m) transactions. These comments requested that the final regulations be amended to explicitly permit withholding agents to rely on this data. Although the final regulations are not amended, the Treasury Department and the IRS note that nothing in the regulations prohibits a taxpayer from obtaining information from a third party. While taxpayers and withholding agents can use third party data to determine whether a potential section 871(m) transaction is a section 871(m) transaction, taxpayers and withholding agents that rely on third-party data remain responsible for the accuracy of that information.

One comment noted that the issuer of a structured note (or an affiliate of the issuer) may act as a market maker for the structured note, and thus may purchase the note in its dealer capacity and then sell the note to the market. According to the comment, if the purchase is treated as a redemption by the issuer of the instrument for tax purposes, the subsequent sale to the market would be treated as a new issue for section 871(m) purposes, in which case the delta for the instrument (or substantial equivalence test) would need to be recomputed at such time. The comment suggested that rules similar to those in section 108 with respect to the purchase of debt instruments by an issuer acting in a dealer capacity could apply to equity derivative structured notes. The Treasury Department and the IRS acknowledge the concern raised by the comment. However, the Treasury Department and the IRS are concerned that an overly broad exception for dealer activity may facilitate transactions that are inconsistent with section 871(m) by allowing dealers to offer instruments that would be subject to section 871(m) so long as the instruments were originally issued with a delta below 0.80. While a dealer that issued such an instrument holds the instrument in inventory, the dealer does not need to hedge the position with an unrelated party. For this reason, market making activity by the issuer of an instrument (or an affiliate of the issuer) presents different policy concerns from market making by an unrelated dealer. The Treasury Department and the IRS invite further comments on the appropriate treatment of structured notes and similar instruments that are acquired by the issuer or an affiliate in its dealer capacity.

Comments to the 2013 proposed regulations generally agreed that the delta test was fair and practical for the majority of equity-linked derivatives. However, comments explained that the delta test would be impractical or impossible to apply to more exotic equity derivatives, such as structured notes in which the long party’s return was determined based on an initially indeterminate number of shares of the underlying security. The 2015 section 871(m) regulations address this concern by providing an alternative test—the “substantial equivalence test”—for contracts with indeterminate deltas. For purposes of applying this test, the regulations distinguish between simple and complex contracts. Generally, a simple contract is a contract that references a single, fixed number of shares and has a single maturity or exercise date. A complex contract is any contract that is not a simple contract. Contracts with indeterminate deltas are classified as complex contracts and are subject to the substantial equivalence test.

Generally, the substantial equivalence test measures the change in value of a complex contract when the price of the underlying security referenced by that contract is hypothetically increased by one standard deviation or decreased by one standard deviation (each, a “testing price”) and compares that change to the change in value of the shares of the underlying security that would be held to hedge the complex contract when the contract is issued (the “initial hedge”) at each testing price. The smaller the proportionate difference between the change in value of the complex contract and the change in value of its initial hedge at multiple testing prices, the more equivalence there is between the contract and the referenced underlying security. When this difference is equal to or less than the difference for a simple contract benchmark with a delta of 0.80 and its initial hedge, the complex contract is treated as substantially equivalent to the underlying security. When the steps of the substantial equivalence test cannot be applied to a particular complex contract, a taxpayer must use the principles of the substantial equivalence test to reasonably determine whether the complex contract is a section 871(m) transaction with respect to each underlying security.

The Treasury Department and the IRS requested comments regarding the substantial equivalence test. In particular, comments were requested on whether two testing points were adequate to ensure that the test would capture appropriate transactions and on the administrability of the test. Comments also were requested on the application of the test to complex contracts that reference multiple securities, including path-dependent instruments (that is, an instrument for which the final value depends, in whole or in part, on the price sequence (or path) of the underlying security before the maturity of the instrument). Comments generally did not recommend material changes to the test. As a result, these final regulations adopt the substantial equivalence test as proposed in the 2015 proposed regulations with minor changes as described in this section.

One comment noted that the substantial equivalence test might be unduly burdensome in certain cases, such as when it is obvious that a particular instrument would satisfy the test and application of the test would have no effect on the amount of withholding. This comment suggested that an issuer of a complex contract be allowed to use an alternative test to determine the withholding tax imposed with respect to a dividend equivalent as long as the alternative test resulted in the same amount of withholding tax as would have been the case if the issuer had used the substantial equivalence test. These final regulations do not adopt this comment. Even in those cases where the result for a potential section 871(m) transaction is intuitive, administration of such an alternative approach would generally require applying the substantial equivalence test to demonstrate that the alternative test results in the same amount of withholding tax as the substantial equivalence test. As issuers of complex contracts become proficient with the substantial equivalence test it is expected that it will be relatively straightforward to determine whether a particular instrument is subject to withholding under section 871(m).

Another comment suggested that the Treasury Department and the IRS consider whether the substantial equivalence test could be manipulated to allow taxpayers to understate the similarity of a complex contract to the underlying security. This comment suggested that more guidance should be offered about the criteria for determining whether a simple contract is “closely comparable” to a complex contract for purposes of choosing a simple contract benchmark. The same comment recommended that the regulations specify that the benchmark contract could be a hypothetical instrument, and that the material terms, including the treatment of dividends, should be consistent with the terms of the complex contract (aside from the terms that make the contract complex and that make the delta of the closely comparable benchmark 0.8).

In response to this comment, the final regulations provide that the simple contract benchmark may be an actual or hypothetical simple contract that, at the time the substantial equivalence test is applied to the complex contract, has a delta of 0.8, references the applicable underlying security referenced by the complex contract, and has terms that are consistent with all the material terms of the complex contract, including the maturity date. In addition, to further ensure comparability between the simple contract benchmark and the complex contract, the final regulations provide that the simple contract benchmark must consistently apply reasonable inputs, including a reasonable time period for the contract. For example, the reasonable time period for the contract must be consistently applied in determining the standard deviation and probability, as well as the maturity date and any other terms dependent on that time period.

Section 1.871–15(j) contains rules for determining the amount of the dividend equivalent. In addition, § 1.871–15(j) requires that the amount of a dividend equivalent be determined on the earlier of the record date of the dividend and the day before the ex-dividend date with respect to the dividend. In many cases, the amount of a dividend equivalent will be determined before a withholding agent will be required to withhold any tax pursuant to newly redesignated § 1.1441–2(e)(7) (formerly § 1.1441–2(e)(8)). Comments requested that a foreign holder’s tax liability be deferred until withholding is required, in order to avoid the need for the foreign holder to file a return and pay tax. The comments noted that this approach would be consistent with the general withholding regime under chapter 3 of the Code. With respect to a section 871(m) transaction acquired by a foreign investor after its initial issuance, a comment requested clarification that the foreign investor is only liable for dividends determined on the underlying security during the period that the foreign investor is the beneficial owner of the section 871(m) transaction.

These regulations include several new provisions in response to these comments. First, § 1.871–15(j)(4) is added to provide that a long party generally is liable for tax on a dividend equivalent in the year the dividend equivalent payment is subject to withholding pursuant to § 1.1441–2(e)(7), or in the case of a QDD, when the payment of the applicable dividend on the underlying security is subject to withholding.

Second, the regulations are amended to clarify that the amount of a dividend equivalent subject to tax will not change because the tax is withheld at a later date. Section 1.871–15(j)(2) establishes the time for determining the amount of a dividend equivalent; the amount of the long party’s tax liability should not change because the withholding agent does not withhold at the time the tax liability arises. Therefore, changes in facts (such as the tax rate or whether the recipient is a qualified resident of a country with which the U.S. has an income tax treaty) between the time that the amount of a dividend equivalent is determined and the time that withholding occurs, do not affect tax liability. For example, if at the time for determining the dividend equivalent amount, the long party qualifies for a treaty, but in the year the amount is withheld the long party does not, the dividend equivalent would qualify for treaty benefits.

Finally, § 1.871–15(j)(1) expressly provides that the long party is only liable for tax on dividend equivalents that arise while the long party is a party to the transaction. For example, if long party A, a foreign person, enters into a section 871(m) transaction on an underlying stock that pays quarterly dividends, and sells the transaction to B, a foreign person, after four dividends on the underlying stock have been paid, A will be subject to tax on those four dividend equivalents and B will be subject to tax on subsequent dividend equivalents as long as B holds the section 871(m) transaction. Alternatively, if A is a U.S. person, B would still only be subject to tax on the dividend equivalents after it acquires the transaction.

Section 1.871–15(l) provides a safe harbor for derivatives based on certain qualified indices. Section 1.871–15(l)(1) provides that the purpose of the exception for qualified indices is to provide a safe harbor for potential section 871(m) transactions that reference certain passive indices, and that an index is not a qualified index if treating the index as a qualified index would be contrary to this purpose. Section 1.871–15(l)(4) provides a specific safe harbor for derivatives based on an index in which the U.S. stock components comprise, in the aggregate, 10 percent or less of the weighting of all the component securities in the index. A comment regarding the 10 percent safe harbor indicated that some taxpayers, notwithstanding the purpose test for indices in § 1.871–15(l)(1), may seek to use a customized index to make tax-advantaged investments in specific U.S. stocks. Although the index described by the comment may not be a qualified index as a result of the purpose rule in § 1.871–15(l)(1), the final regulations are revised to clarify that, in order to meet this 10 percent safe harbor, an index must be widely traded and must not be formed or availed of with a principal purpose of tax avoidance.

Comments to the qualified indices rules in the 2015 final regulations also requested that the Treasury Department and the IRS address how the rules apply to an index in the first year it is created. Accordingly, these final regulations add § 1.871–15(l)(2)(ii) to provide that, for the first year, an index is tested on the first business day it is listed, and the dividend yield calculation is determined using the dividend yield that the index would have had in the immediately preceding year if it had the same components throughout that year that it has on the day it is created.

For purposes of determining whether transactions are section 871(m) transactions, the 2015 final regulations treat two or more transactions as a single transaction when a long party (or a related person) enters into multiple transactions that reference the same underlying security, the combined potential section 871(m) transactions replicate the economics of a transaction that would be a section 871(m) transaction, and the transactions were entered into in connection with each other. The 2015 final regulations also provide brokers acting as short parties with two presumptions that may be applied to determine whether to combine potential section 871(m) transactions. First, a broker may presume that transactions are not entered into in connection with each other if the long party holds the transactions in separate accounts. Second, a broker may presume that transactions entered into two or more business days apart are not entered into in connection with each other. A broker, however, cannot rely on the first presumption if it has actual knowledge that the long party created or used separate accounts to avoid section 871(m). In addition, neither presumption applies if the broker has actual knowledge that transactions were entered into in connection with each other. Section 1.1441–1(b)(4)(xxiii) also permits withholding agents to rely on these presumptions.

Comments suggested several changes to the combined transaction rules. Comments noted that it will be burdensome to identify every contract that a customer entered into with respect to the same underlying security within two days of each other. To replace the presumptions, comments recommended that a withholding agent only be required to combine contracts if the withholding agent had actual knowledge that two contracts were priced, marketed, or sold in connection with each other.

The Treasury Department and the IRS disagree that the priced, marketed, or sold standard should replace the combination presumptions. Comments noted a “not uncommon” example of an active foreign investor who acquires or sells within a two-day period hundreds of listed options referencing the same underlying security. The Treasury Department and the IRS, however, intended to treat those transactions as combined to the extent that the potential section 871(m) transactions are entered into in connection with each other and satisfy the other requirements of § 1.871–15(n)(1). The priced, marketed, or sold standard provides an inadequate substitute for the combined transaction test and the presumptions because investors can replicate a section 871(m) transaction by entering into multiple potential section 871(m) transactions. For example, an investor could replicate a delta one transaction by entering into a put option and a call option on the same underlying security at the same time, with the same strike price, whether or not the options are priced, marketed, or sold together. For this reason, the priced, marketed, or sold standard provides an inadequate substitute for the presumptions. The comments submitted with respect to the combination rule acknowledge short parties and withholding agents are aware that foreign investors use multiple transactions in a manner that are combined under the final regulations. The “priced, marketed, or sold” standard would undermine the enforcement of the combination rules.

Notwithstanding the prior paragraph, Notice 2016–76 provides a simplified standard for withholding agents to determine whether transactions entered into in 2017 are combined transactions. A withholding agent will only be required to combine transactions entered into in 2017 for purposes of determining whether the transactions are section 871(m) transactions when the transactions are over-the-counter transactions that are priced, marketed, or sold in connection with each other. Withholding agents will not be required to combine any transactions that are listed securities that are entered into in 2017.

Another comment noted that the final regulations indicated that transactions would only be combined into simple contracts. This comment recommended that the final regulation be amended if the Treasury Department and the IRS disagreed with this reading of the combination rule. The Treasury Department and the IRS agree that transactions will only be combined into simple transactions pursuant to § 1.871–15(n); therefore, the final regulations are not amended.

Other comments suggested some clarifications to the combination rules to resolve ambiguities. For example, comments requested, among other things, that (1) ordering rules provide that a contract cannot be combined more than once and (2) no combination transaction should have a delta of more than one. The final regulations are not amended to address these issues because the final regulations are intended to provide a general framework for determining when two or more transactions should be combined. The comments received to date show that industry understanding of how the combination rules may be administered continues to develop as financial institutions work to establish systems. As this understanding evolves, the Treasury Department and the IRS may publish subsequent guidance to address the issues raised by these comments. Until such further guidance is issued, taxpayers may adopt any reasonable methodology to combine transactions within the general framework of the final regulations.

The 2015 final regulations provide that when one of the parties to a potential section 871(m) transaction is a broker or dealer, that broker or dealer is responsible for determining whether the transaction is a section 871(m) transaction. When both parties to a potential section 871(m) transaction are a broker or dealer or neither party to a potential section 871(m) is a broker or dealer, the short party to the transaction must determine whether the transaction is a section 871(m) transaction.

Comments noted that multiple parties could be responsible for determining whether a transaction is a section 871(m) transaction because the definition of a “party to the transaction” includes a long party, a short party, any agent acting on behalf of a long party or short party, and any person acting as an intermediary with respect to a potential section 871(m) transaction. Comments noted that both a short party and one or more agents of the short party may be a broker or dealer; in this case, the 2015 final regulations do not identify which of the responsible parties has the primary obligation to determine whether the transaction is a section 871(m) transaction.

Comments requested that the regulations clarify which broker has the obligation to determine whether a listed option is a section 871(m) transaction when multiple brokers or dealers are involved. One comment recommended that the long party’s broker that has custody of the transaction at the end of the day would be best suited to act as the responsible party. Comments also noted that the short party or the agent of a short party may not have the relevant information necessary to determine when withholding should take place. For example, when a long party has sold an instrument in the secondary market, the short party and its agent may not have any knowledge of that sale. As a result, the long party’s broker should be the responsible party.

Other comments indicated that the issuer should be the responsible party when the issuer itself is a broker or a dealer, or when the issuer has an affiliate that is a broker or dealer. In these cases, the issuer or its affiliate is likely to have the information necessary to determine whether the transaction is a section 871(m) transaction. As noted in other comments, an intermediary to a transaction issued by a broker or dealer, such as a clearinghouse, will not have the information necessary to determine whether a potential section 871(m) transaction is a section 871(m) transaction, and is unlikely to know either the time or the amount to withhold.

The Treasury Department and the IRS agree that the final regulations may result in multiple parties to a transaction qualifying as the party responsible for determining whether a potential section 871(m) transaction is a section 871(m) transaction. New temporary regulations resolve this duplication of responsible parties under § 1.871–15(p)(1) in the following circumstances: (1) both the short party and an agent or intermediary of the short party are a broker or a dealer; (2) the short party is not a broker or dealer and more than one of the agents or intermediaries of the short party is a broker or dealer; (3) the short party and its agents or intermediaries are not brokers or dealers, and more than one agent or intermediary acting on behalf of the long party is a broker or dealer; and (4) potential section 871(m) transactions are traded on an exchange and cleared by a clearing organization.

Specifically, § 1.871–15T(p)(1)(ii) provides that the short party is the responsible party when both the short party and an agent or intermediary acting on behalf of the short party are a broker or dealer. In these circumstances, the Treasury Department and the IRS have determined that the short party should be the responsible party because it will have access to the relevant data regarding that transaction, whereas an agent or intermediary may not have the necessary information. As the responsible party, the short party may contract with a third party to make the determinations on its behalf; however, the short party remains responsible for the accuracy of any calculations by the third party.

In addition, if the short party is not a broker or dealer, but more than one agent or intermediary acting on behalf of the short party is a broker or dealer, § 1.871–15T(p)(1)(ii) provides that the broker or dealer closest to the short party in the payment chain is the responsible party. The Treasury Department and the IRS have determined that the agent or intermediary closest in the chain to the short party will have the best access to any information the short party has that is necessary to determine whether a potential section 871(m) transaction is a section 871(m) transaction and to make other relevant determinations.

Section 1.871–15T(p)(1)(ii) also generally provides that when one or more agents or intermediaries acting on behalf of the long party are brokers or dealers, the agent or intermediary that is closest to the long party in the payment chain is the responsible party when neither the short party nor any agent or intermediary acting on behalf of the short party is a broker or dealer. In this situation, the temporary regulations place the responsibility with the agent or intermediary closest to the long party because this agent or intermediary will know whether or not the long party is subject to tax under section 871 or 881 and when the long party has terminated or otherwise disposed of the transaction.

Similarly, these temporary regulations also provide a rule for determining the responsible party when potential section 871(m) transactions are traded on an exchange and cleared by a clearing organization. When more than one broker or dealer acts as an agent or intermediary between the short party and a foreign investor on an exchange-traded contract, the broker or dealer that has an ongoing customer relationship with the foreign investor is the responsible party. Generally, this intermediary will be the clearing firm.

Finally, these temporary regulations provide that the issuer of a potential section 871(m) transaction will be the responsible party for certain ELIs. Specifically, the issuer is the responsible party for structured notes (including contingent payment debt instruments), warrants, convertible stocks, and convertible debt instruments. Because the issuer of these ELIs ordinarily will have structured the ELI, determined the pricing of the ELI, and hedged the ELI, the issuer ordinarily will be in the best position to act as the responsible party. While the issuer of an ELI may not be a broker or dealer, an issuer of an ELI typically is advised by a broker or dealer.

Section 1.871–15T(q) permits a QDD to reduce its liability under section 871 or 881 for a dividend or dividend equivalent to the extent it makes an offsetting dividend equivalent payment in its dealer capacity. Only an eligible entity that has entered into a QI agreement can be a QDD. An eligible entity is defined as: (1) a dealer in securities subject to regulatory supervision as a dealer, (2) a bank subject to regulatory supervision as a bank, or (3) a wholly-owned entity of a bank subject to regulatory supervision as a bank when the wholly-owned entity (a) issues potential section 871(m) transactions to customers and (b) receives dividends or dividend equivalent payments from stock or potential section 871(m) transactions that hedge the potential section 871(m) transactions issued to customers. § 1.1441–1T(e)(6). An entity is only a QDD when acting in its QDD capacity.

 

In general, section 871(m) and the regulations thereunder apply to a dividend equivalent payment without regard to whether the payor of the dividend equivalent payment is domestic or foreign. Section 1.894–1(c)(2) provides that “[t]he provisions of an income tax convention relating to dividends paid to or derived by a foreign person apply to the payment of a dividend equivalent described in section 871(m) and the regulations thereunder.” Consistent with the foregoing, the 2017 QI Agreement provides that a QDD must treat any dividend equivalent as a dividend from sources within the United States for purposes of section 881 and chapters 3 and 4 consistent section 871(m) and the regulations thereunder. The 2017 QI Agreement provides that a QDD may reduce the rate of withholding under chapter 3 based only on a beneficial owner’s claim that it is entitled to a reduced rate of withholding for portfolio dividends under the dividends article of an applicable income tax treaty.

Comments requested that the Treasury Department and the IRS expand the scope of entities that qualify as an eligible entity under § 1.1441–1(e), and therefore can act as a QDD under a QI agreement. One comment requested that the eligibility criteria be expanded to permit a controlled foreign corporation (CFC) of a U.S financial institution to act as a QDD even if the CFC is not a QI. Other comments recommended that the definition of an eligible entity be expanded to include a bank holding company if the entity regularly issues potential section 871(m) transactions to customers and receives dividends or dividend equivalent payments pursuant to potential section 871(m) transactions to hedge the transactions issued to customers. Comments noted that a bank holding company is subject to a wide range of regulatory regimes.

Comments also recommended that the scope of eligible entities be expanded to include subsidiaries of securities dealers and bank holding companies that regularly issue potential section 871(m) transactions to customers and receive dividends or dividend equivalent amounts with respect to hedges of those customer transactions. Comments noted that these entities are part of a regulated financial group.

In response to comments, the 2017 QI Agreement announced the expansion of the definition of eligible entities to include a bank holding company and subsidiaries of a bank holding company. The Treasury Department and the IRS agree that a bank holding company and subsidiaries of a bank holding company should be included in the definition of an eligible entity because these entities are regulated financial institutions.

The 2017 QI Agreement clarified that the eligible entity test is applied at the home office or branch level, and that each home office or branch is a separate QDD. The 2017 QI Agreement also expanded what constitutes an eligible entity to include a foreign branch of a U.S. financial institution that would meet the requirements of an eligible entity if the branch were a separate entity, though such a branch will not be subject to tax on its QDD tax liability because it is otherwise subject to tax on a net income basis under chapter 1. Both of these changes are incorporated in these final regulations. These final regulations also clarify that a subsidiary of a bank or bank holding company could be indirectly wholly-owned by the qualifying bank or bank holding company provided that the subsidiary, acting in its equity derivatives dealer capacity, (1) issues potential section 871(m) transactions to customers, and (2) receives dividends with respect to stock or dividend equivalent payments pursuant to potential section 871(m) transactions that hedge potential section 871(m) transactions that it issues.

These final regulations do not expand the eligible entity definition to specifically include CFCs. The comments generally did not adequately explain why CFCs cannot avail themselves of the QI regime (with the QDD provisions). Permitting CFCs that are not QIs to be QDDs would eliminate the compliance benefits provided in the 2017 QI Agreement and would make it more difficult for the IRS to verify compliance with the QDD rules. However, to provide the IRS with flexibility to administer the QDD regime, an eligible entity is defined to include any other person acceptable to the IRS, which is similar to the allowance provided to the IRS in defining persons eligible to enter into a QI agreement as provided in § 1.1441–1(e)(5)(ii)(D).

A comment also raised a technical issue with who can qualify as a QI, expressing concern that some eligible entities that are not foreign financial institutions may not be able to enter into QI agreements because they are not eligible to become a QI. The 2017 QI Agreement and these final regulations now clarify that an eligible entity (notwithstanding that the entity otherwise would not be eligible to be a QI) can enter into a QI agreement in order to implement the QDD provisions.

Section 1.871–15T(q)(1) of the 2015 temporary regulations provided that a QDD generally would not be liable for tax under section 871 or 881 on a dividend or dividend equivalent payment that the QDD receives in its capacity as a QDD, provided that the QDD complies with its obligations under the qualified intermediary agreement. Section 1.1441–1T(e)(6) of the 2015 temporary regulations provided that a QDD would not be subject to withholding on such dividends or dividend equivalents. Section D of this Part IX describes certain changes to the foregoing rules that the Treasury Department and the IRS determined are appropriate in light of the adoption of the net delta approach described in this Part IX.C.

Section 1.871–15T(q)(1) of the 2015 temporary regulations further provides that, if a QDD receives a dividend or dividend equivalent payment and the offsetting dividend equivalent payment the QDD is contractually obligated to make on the same underlying security is less than the dividend and dividend equivalent amount the QDD received, the QDD would be liable for tax under section 871(a) or 881 for the difference.

The QI Notice described proposed changes to the QI agreement that would implement the QDD tax liability described in § 1.871–15T(q). Under the QI Notice, a QDD’s section 871(m) amount for a dividend was the excess of the dividends on underlying securities associated with potential section 871(m) transactions and dividend equivalent payments that it received that reference the same dividend over dividend equivalent payments and any qualifying dividend equivalent offsetting payment that the QDD made or was contractually obligated to make with respect to the same dividend. The QI Notice described a qualifying dividend equivalent offsetting payment as (a) any payment made or contractually obligated to be made to a United States person that would be a dividend equivalent payment if made to a person who was not a United States person and (b) any payment made to a foreign person that would be a dividend equivalent payment if the payment were not treated as income effectively connected with the conduct of a U.S. trade or business.

In addition, the QI Notice proposed rules regarding how a QDD would calculate its QDD tax liability. Specifically, under the QI Notice, the QDD tax liability was the sum of a QDD’s liability under sections 871(a) and 881 for (a) its section 871(m) amount; (b) its dividends that are not on underlying securities associated with potential section 871(m) transactions and its dividend equivalent payments received as a QDD in its non-dealer capacity; and (c) any other payments, such as interest, received as a QDD with respect to potential section 871(m) transactions or underlying securities that are not dividend or dividend equivalent payments.

Comments requested that a QDD be permitted to elect to calculate its section 871(m) amount either by using (1) the method described in the QI Notice or (2) its net delta exposure to an underlying security. According to comments, the net delta exposure is a calculation, measured in shares of stock, that aggregates all the shares of an underlying security and all equity derivative transactions referring to the same underlying security that the QDD has entered into in a dealer capacity (whether customer transactions or hedging transactions). Comments explained that net delta accurately measures a QDD’s residual exposure to an underlying security. Comments noted that financial institutions use net delta exposure for business and non-tax regulatory purposes.

Comments also requested that the Treasury Department and the IRS expand the offsetting dividend equivalent payment to include all customer transactions, such as potential section 871(m) transactions with a delta below 0.8, grandfathered transactions, and transactions that reference a qualified index.

In response to comments relating to the QI Notice, Notice 2016–76 announced that the regulations would be revised to require a QDD to calculate its section 871(m) amount based on the net delta approach. The Treasury Department and the IRS agree that the net delta approach provides an administrable and accurate method for a QDD to determine its residual exposure to underlying securities. The Treasury Department and the IRS, however, do not agree with comments indicating that QDDs should be permitted to elect to use the net delta exposure method or the rule described in the QI Notice. It would be burdensome to the IRS to administer a system that permits a QDD to use multiple methods to calculate its section 871(m) amount. The Treasury Department and the IRS, however, will consider comments that explain in more detail why a choice of methods for determining the section 871(m) amount is in the best interests of both taxpayers and the government.

These final regulations further explain how a QDD’s section 871(m) amount is computed. The amount is determined separately for each dividend on an underlying security. For example, if a QDD enters into section 871(m) transactions that reference stock A (which pays a $5 dividend per share), hedges the transactions by acquiring actual shares of stock, and has a net delta exposure to one share of stock, the QDD will have a tax liability pursuant to sections 871(a) and 881 with respect to a $5 dividend based on its net delta exposure to one share of stock A. Amounts with respect to other dividends on the same stock or another stock are not taken into account.

Because these final regulations adopt the net delta exposure method for calculating the section 871(m) amount, the concepts of offsetting dividend equivalent payments and qualifying dividend equivalent offsetting payments have been eliminated from these final regulations.

These final regulations revise the calculation of a QDD’s tax liability on the section 871(m) amount to correspond with the changes regarding the determination of the section 871(m) amount discussed in this section and the changes to withholding on payments to a QDD that are discussed in the following section of this preamble. Specifically, a QDD’s tax liability on its section 871(m) amount is, for each dividend on each underlying security, the amount by which its tax liability under section 881 for its section 871(m) amount exceeds the amount of tax paid by the QDD under section 881 (including amounts withheld on payments to the QDD) on dividend payments received by the QDD in its capacity as an equity derivatives dealer. The QDD also is liable for tax under section 881 for dividend equivalent payments received by a QDD in its non–equity derivatives dealer capacity and for any other payments (including dividends) it receives as a QDD to the extent the full liability was not satisfied by withholding.

In general, under the law in effect prior to 2017, an eligible entity that would qualify as a QDD under these final regulations generally was subject to tax under section 881 and to withholding tax under chapters 3 and 4 on actual dividends in the same manner as any other foreign recipient. As described in the preceding section, the 2015 temporary regulations provided that a QDD would no longer be subject to tax or to withholding on actual dividends received in its capacity as a QDD. The Treasury Department and the IRS are concerned that this exemption in the 2015 temporary regulations, when combined with the net delta exposure method, could result in U.S. source dividends escaping U.S. tax completely in certain circumstances. For example, if a QDD holds physical shares of an underlying security that it uses to hedge a delta 0.5 option, both the dividend and the option would not be subject to tax under section 871 or section 881. In response to this concern, Notice 2016–76 announced that the Treasury Department and the IRS intended to revise §§ 1.871–15T(q)(1) and 1.1441–1(b)(4)(xxii) to provide that a QDD will remain liable for tax under section 881(a)(1) and subject to withholding under chapters 3 and 4 on dividends on physical shares and deemed dividends received. These final regulations revise §§ 1.871–15T(q)(1) and 1.1441–1(b)(4)(xxii) accordingly. However, as announced in the 2017 QI Agreement, in order to allow taxpayers time to implement the net delta approach, these regulations continue to provide that dividends on physical shares and deemed dividends received by a QDD in its QDD capacity in 2017 will not be subject to tax under section 881(a)(1) or subject to withholding under chapters 3 and 4. A QDD will be subject to withholding on dividends (including deemed dividends) received on or after January 1, 2018.

The Treasury Department and the IRS will consider comments recommending approaches for alleviating any overwithholding (and preventing any underwithholding) that might occur on dealer transactions with customers and on positions that hedge customer transactions when withholding on dividends (including deemed dividends) paid to QDDs resumes in 2018.

The QI Notice provided that a withholding agent (other than a withholding agent that itself was acting as a QDD) would not be required to withhold or report on payments made to a QDD with respect to potential section 871(m) transactions and underlying securities, other than reporting for dividends and substitute dividends. A comment requested that a withholding agent should only be exempt from withholding and reporting on dividends and dividend equivalents paid to a QDD. In response to this comment, the 2017 QI Agreement provides that all payments (other than dividend equivalent payments) made to a QDD with respect to underlying securities will be subject to withholding and reporting if the payments would be subject to withholding and reporting to a non-QDD. Consistent with the 2017 QI Agreement, the final regulations provide that all payments (other than dividend equivalent payments) made to a QDD with respect to underlying securities will be subject to withholding and reporting if those payments would be subject to withholding and reporting when received by a foreign person.

The 2015 temporary regulations only permitted a taxpayer to act as a QDD with respect to certain payments received in its dealer capacity. Comments requested that a taxpayer be permitted to act as a QDD for payments received in its proprietary capacity for administrative reasons. The QI Notice and the 2017 QI Agreement reflect this change to the scope of QDD payments. The change in QDD scope does not impact the limitation on amounts entitled to be offset, which remain limited to dealer activity.

Consistent with the 2015 regulations, the QI Notice and the 2017 QI Agreement provide that, for purposes of determining the QDD tax liability, payments received by a QDD acting as a proprietary trader are treated as payments received in its non-dealer capacity, while transactions properly reflected in a QDD’s dealer book are presumed to be held by a dealer in its dealer capacity. For purposes of determining the QDD tax liability, dealer activity is limited to its activity as an equity derivatives dealer. One comment requested that the regulations clarify and qualify the distinction between receiving a payment in a dealer versus in a proprietary trader capacity and the impact of the distinction on the ability of an entity to act as a QDD. The Treasury Department and the IRS have determined that the regulations adequately delineate between dealer and proprietary transactions in § 1.871–15(q)(2).

Generally, newly redesignated § 1.1441–2(e)(7) (formerly § 1.1441–2(e)(8)) provides that a withholding agent must withhold on a dividend equivalent on the later of the date on which the amount of the dividend equivalent is determined and the date that a payment occurs. A payment generally occurs when money or other property is paid to or by the long party, or the long party sells, exchanges, transfers, or otherwise disposes of a section 871(m) transaction. Notwithstanding this general rule applicable to withholding agents, the QI Notice announced that a QDD must withhold with respect to a dividend equivalent payment on the dividend payment date for the applicable dividend on the underlying security as determined in § 1.1441–2(e)(4).

Comments noted that this change would require a QDD to pay tax prior to the date that other withholding agents would have been required to withhold. In addition, comments expressed concern that this rule would result in cashless withholding for many transactions. Comments also noted that withholding agents have been building withholding systems according to the general rule provided in the final section 871(m) regulations. Comments recommended that the final section 871(m) regulations be amended to permit a QDD to elect to withhold on the payment of the dividend equivalent as provided in newly redesignated § 1.1441–2(e)(7) or on the dividend payment date as determined in § 1.1441–2(e)(4).

The Treasury Department and the IRS have determined that a QDD should continue to be required to withhold on the dividend payment date as determined in § 1.1441–2(e)(4), because the time that a QDD withholds on customer transactions should match the time period for which it determines its own tax liability with respect to the section 871(m) amount. This is because the withholding tax that may apply to customer transactions is the justification for relieving the QDD from tax on its section 871(m) amount. In addition, this rule simplifies the reconciliation statement, makes it easier for reviewers and the IRS to verify that a QDD has complied with the requirements of the 2017 QI Agreement, and avoids a number of other issues that would arise under the requested approach, including statute of limitation issues. With respect to the concerns expressed regarding the need to build systems, the Treasury Department and the IRS note that this timing rule is consistent with the rule that was proposed in the QI Notice, released July 1, 2016. Moreover, as described in Notice 2016–76, during 2017, the IRS will take into account the extent to which a QDD has made a good faith effort to comply with the QDD provisions in the QI agreement when enforcing those provisions.

Notice 2010–46, 2010–24 I.R.B. 757 (see § 601.601(d)(2)(ii)(b)), (QSL Notice) outlined a proposed credit forward system that allowed a withholding agent to limit the aggregate U.S. gross-basis tax in a series of securities lending transactions to the amount of U.S. gross-basis tax applicable to the foreign taxpayer receiving a substitute or actual dividend in the series of transactions who bears the highest rate of U.S. gross-basis tax. The preamble to the 2015 regulations indicated that the credit forward system remained under consideration, but noted that, during the transition period provided in Notice 2010–46, the IRS has experienced difficulty verifying that prior withholding has occurred. Comments were requested on the need for the regime and how it could be implemented.

Comments requested that the credit forward system be retained. One comment requested that the credit forward system be retained when QDD status was not available. In contrast, another comment suggested that the stringency resulting from tightening the eligibility requirements for QDDs to QIs that are subject to reporting and compliance requirements would improve the ability to verify that prior withholding occurred.

As discussed in Part IX.B of this preamble the Treasury Department and the IRS have concluded that it is not appropriate to permit credits or offsets for any entity that does not qualify as an eligible entity. In reaching this conclusion, the Treasury Department and the IRS agree with the comment that indicated that the QDD rules provide a more administrable method of determining that withholding properly occurred. If the entity is acting as an intermediary instead of acting as a principal, it may choose to be a QI that is not a QDD. The second comment did not explain why the existing QDD regime is insufficient.

In addition to comments regarding the credit forward system, a comment requested that QSL status be preserved as a standalone rule for securities lending transactions that are part of a separate line of business from other potential section 871(m) transactions. Another comment recommended reverting to the eligibility requirements for a QSL in the QSL Notice by extending QDD status to custodian QIs that are subject to regulatory supervision by a governmental authority in the jurisdiction in which the entity was created, as long as the entity agrees to assume primary withholding and reporting responsibility with respect to dividend equivalent payments and complies with all QDD certification requirements.

While the Treasury Department and the IRS understand that the QSL regime was administratively more convenient for taxpayers than the QI regime, it created administrability problems, particularly with respect to verification, for the IRS. That regime is being replaced by incorporating the QDD rules into the existing QI framework, including the specific rules for pooled reporting on Form 1042–S, and the QI requirements for compliance review and certification. With respect to banks, custodians, and clearing organizations that do not issue potential section 871(m) transactions to customers, the Treasury Department and the IRS are concerned that reverting to the eligibility requirements for a QSL in the QSL Notice would permit an entity to act as a QDD that does not act as a financial intermediary in a chain of section 871(m) transactions.

As part of the transition relief announced in Notice 2016–76, the Treasury Department and the IRS announced that taxpayers may continue to rely on the QSL Notice during 2017. The QSL Notice will be obsoleted as of January 1, 2018.

Newly designated § 1.1441–2(e)(7) provides that a withholding agent is not obligated to withhold on a dividend equivalent until the later of when a payment is made with respect to a section 871(m) transaction and when the amount of a dividend equivalent is determined. For purposes of § 1.1441–2(e)(7), a payment with respect to a section 871(m) transaction occurs when the long party receives or makes a payment, when there is a final settlement of the section 871(m) transaction, or when the long party sells or otherwise disposes of the section 871(m) transaction. The 2015 final regulations adopted this approach in response to taxpayer comments.

The 2015 final regulations provide that a payment occurs when the long party sells or disposes of a section 871(m) transaction; however, when a long party transfers a section 871(m) transaction from one broker or custodian to another broker or custodian, the 2015 final regulations do not treat that transfer as a payment. A comment noted that it is common for investors to change relationships with brokers and custodians who hold their securities, which may result in section 871(m) transactions being transferred from one broker or custodian to another. The comment asserted that it is inappropriate and burdensome for a withholding agent to be responsible for dividend equivalent amount calculations relating to dividends that occurred before the date that the new broker or custodian holds the section 871(m) transaction on behalf of a long party. The comment recommended that the Treasury Department and the IRS amend the 2015 final regulations to provide that a transfer of a section 871(m) transaction from one broker or custodian to another, without a change in beneficial ownership, constitutes a payment for purposes of § 1.1441–2(e)(7).

The Treasury Department and the IRS agree that requiring a broker or custodian to withhold on dividend equivalent payments that occurred before holding a section 871(m) transaction on behalf of a customer would be burdensome to the withholding agent. As a result, § 1.1441–2(e)(7) is revised to provide that a payment of a dividend equivalent occurs when a section 871(m) transaction is transferred to an account not maintained by the withholding agent or upon a termination of the account relationship.

While § 1.1441–2(e)(7) generally defers withholding on a section 871(m) transaction until there is a payment made pursuant to the transaction, comments noted that § 1.1441–2(e)(7) will require cashless withholding in certain circumstances. To implement the 2015 final regulations, comments noted that market participants would be required to develop or amend collateral and indemnity arrangements with customers. Some comments recommended amending the 2015 final regulations to allow withholding agents to treat a dividend equivalent as paid and subject to withholding on the dividend payment date for the underlying security referenced by the section 871(m) transaction. Comments indicated that some withholding agents believe that it will be easier to implement withholding on the dividend payment date for the underlying security because their systems are already designed to track the time and amount of actual dividends. Many withholding agents, however, have contractual agreements with customers that prohibit withholding earlier than a date permitted by regulations.

The Treasury Department and the IRS appreciate that some withholding agents would rather not develop new systems to track dividend equivalents over multiple years, while other financial institutions prefer the time for withholding provided by § 1.1441–2(e)(7). To accommodate both approaches, the Treasury Department and the IRS are amending the regulations to allow withholding agents the flexibility to withhold either based on the “later of” rule, as determined under § 1.1441–2(e)(7), or on the dividend payment date for the underlying security. This change will allow withholding agents that prefer to withhold on the dividend payment date to do so, without eliminating the “later of” rule in § 1.1441–2(e)(7) that generally ties withholding to a cash payment. As discussed in Part IX.F of this preamble, if a withholding agent acts as a QDD, it will be required to use the dividend payment date.

A withholding agent that chooses to withhold on the dividend payment date for the underlying security referenced by the section 871(m) transaction must apply the election consistently to all section 871(m) transactions of the same type. In other words, a withholding agent that chooses to withhold on the dividend payment date for securities lending transactions must do so for all securities lending transactions, but may choose to withhold on NPCs under the rule in § 1.1441–2(e)(7). When a withholding agent withholds on the dividend payment date under this alternate method, the withholding agent must notify each payee in writing before the time for determining the long party’s first dividend equivalent payment. A withholding agent that withholds on the dividend payment date for the underlying security also must attach a statement to its Form 1042 for the year of the change notifying the IRS of the change and when it applies.

The current regulations provide that § 1.871–15(d)(2) and (e) apply to any payment made on or after January 1, 2017, with respect to any transaction issued on or after January 1, 2017. Several comments requested that implementation of these provisions be delayed until at least January 1, 2018. One comment requested that implementation be delayed until at least one year after the date guidance resolving all issues raised by the comment is issued. The primary reasons comments provided for the requests to delay implementation were the need for additional guidance, the need for additional time to make systems operational, and the recent release of additional QDD guidance in the QI Notice and in Notice 2016–76. Comments also requested a delay in the combination rule generally. Another comment agreed with the request for a delayed effective date for the combination rule, unless the rule was revised to require withholding agents only to combine transactions that the withholding agent has actual knowledge are priced, marketed, or sold in connection with each other. A comment also requested a transition period until December 31, 2018, for enforcement and administration of QDD obligations.

The 2013 proposed regulations provided that the proposed sections would apply to payments made on or after the date the regulations were finalized. However, when the regulations were finalized in 2015, the Treasury Department and the IRS provided that the regulations generally would only apply to transactions issued on or after January 1, 2017, to ensure adequate time to develop systems needed to implement the regulations.

Both the 2015 regulations and the amendments to those regulations that are included in these regulations, many of which were previously announced in the QI Notice, Notice 2016–76, and the 2017 QI Agreement, make the withholding required under section 871(m) easier to implement and more administrable. In light of these revisions, the Treasury Department and the IRS have determined that it is not necessary or appropriate to uniformly extend the applicability date for all section 871(m) transactions. In particular, taxpayers have had ample time to develop systems to implement withholding on section 871(m) transactions that are delta one transactions. The Treasury Department and the IRS have determined, however, that taxpayers and withholding agents need additional time to implement the section 871(m) regulations for section 871(m) transactions other than delta one transactions. Accordingly, these regulations postpone the implementation of the section 871(m) regulations with respect to non-delta one transactions until January 1, 2018.

In addition, in response to comments, Notice 2016–76 announced transition relief for combined transactions by providing a simplified rule for withholding agents to determine whether transactions entered into in 2017 are combined transactions. Also in response to comments, Notice 2016–76 delayed the application of section 871(m) for certain exchange-traded notes. Notice 2016–76 also announced that calendar years 2017 and 2018 would be phase-in years. In enforcing and administering section 871(m) (1) with respect to delta-one transactions in 2017, and (2) with respect to non-delta-one transactions in 2018, the IRS will take into account the extent to which the taxpayer or withholding agent made a good faith effort to comply with the section 871(m) regulations. Similarly, Notice 2016–76 and the 2017 QI Agreement provide that calendar year 2017 will be a phase-in year for QDDs. As discussed in Part XI.D, the 2017 QI Agreement and these regulations provide that a QDD will not be subject to withholding on actual or deemed dividends in 2017. Finally, the 2017 QI Agreement and these final regulations do not impose tax on a QDD’s section 871(m) amount for tax years beginning before January 1, 2018.

(a) * * * (1) Broker. [Reserved]. For further guidance, see § 1.871–15T(a)(1).

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(14) * * * (i) Simple contract. A simple contract is an NPC or ELI for which, with respect to each underlying security, all amounts to be paid or received on maturity, exercise, or any other payment determination date are calculated by reference to a single, fixed number of shares (as determined in paragraph (j)(3) of this section) of the underlying security, provided that the number of shares can be ascertained at the calculation time for the contract, and there is a single maturity or exercise date with respect to which all amounts (other than any upfront payment or any periodic payments) are required to be calculated with respect to the underlying security. For purposes of this section, a contract that provides an adjustment to the number of shares of the underlying security for a merger, stock split, cash dividend, or similar corporate action that affects all holders of the underlying securities proportionately will not cease to be treated as referencing a single, fixed number of shares solely as a result of that provision. A contract has a single exercise date even though it may be exercised by the holder at any time on or before the stated expiration of the contract. An NPC or ELI that includes a term that discontinuously increases or decreases the amount paid or received (such as a digital option), or that accelerates or extends the maturity is not a simple contract. A simple contract that is an NPC is a simple NPC. A simple contract that is an ELI is a simple ELI.

* * * * *

(ii) * * * (B) Example. * * * Pursuant to paragraph (j)(3) of the section, the ELI references 200 shares when Stock X appreciates, but only 100 shares when Stock X depreciates. * * *

(c) * * *

(2) * * * (ii) Section 305 coordination. A dividend equivalent received by a long party, who is a shareholder as defined in § 1.305–1(d) of an instrument that gives rise to a dividend pursuant to sections 305(b) and (c) (including a debt instrument that is convertible into shares of stock and stock that is convertible into shares of another class of stock) that is also a section 871(m) transaction, is reduced by any amount treated as a dividend by sections 305(b) and (c) to the long party. For other section 871(m) transactions that reference an underlying security that is an instrument treated as paying a dividend pursuant to sections 305(b) and (c) and for which the long party is not a shareholder as defined in § 1.305–1(d), the dividend equivalent received by the long party with respect to the section 871(m) transaction includes (and is not reduced by) any amount treated as a dividend pursuant to sections 305(b) and (c).

* * * * *

(iv) Payments made pursuant to annuity, endowment, and life insurance contracts—(A) Insurance contracts issued by domestic insurance companies. A payment made pursuant to a contract that is an annuity, endowment, or life insurance contract issued by a domestic corporation (including its foreign or U.S. possession branch) that is a life insurance company described in section 816(a) does not include a dividend equivalent if the payment is subject to tax under section 871(a) or section 881.

(B) Insurance contracts issued by foreign insurance companies. A payment does not include a dividend equivalent if it is made pursuant to a contract that is an annuity, endowment, or life insurance contract issued by a foreign corporation that would be subject to tax under subchapter L if it were a domestic corporation.

(C) Insurance contracts held by foreign insurance companies. A payment made pursuant to a policy of insurance (including a policy of reinsurance) does not include a dividend equivalent if it is made to a foreign corporation that would be subject to tax under subchapter L if it were a domestic corporation.

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(g) * * *

(2) Time for determining delta—(i) In general. Except as provided in paragraph (g)(4) of this section, the delta of a potential section 871(m) transaction is determined at the calculation time for the potential section 871(m) transaction.

(ii) Calculation time. The calculation time for a potential section 871(m) transaction is the earlier of when the potential section 871(m) transaction is priced and when the potential section 871(m) transaction is issued. Notwithstanding the preceding sentence, if the pricing time is more than 14 calendar days before the potential section 871(m) transaction is issued, the calculation time is when the potential section 871(m) transaction is issued.

(iii) Pricing time. A potential section 871(m) transaction is priced when all material economic terms for the transaction have been agreed upon, including the price at which the transaction is sold.

(3) Simplified delta calculation for certain simple contracts that reference multiple underlying securities. If an NPC or ELI references 10 or more underlying securities and an exchange-traded security (for example, an exchange-traded fund) is available that would fully hedge the NPC or ELI at the calculation time, the delta of the NPC or ELI may be calculated by determining the ratio of the change in the fair market value of the simple contract to a small change in the fair market value of the exchange-traded security. A delta determined under this paragraph (g)(3) must be used as the delta for each underlying security for purposes of calculating the amount of a dividend equivalent as provided in paragraph (j)(1)(ii) of this section.

(4) Delta calculation for listed options—(i) In general. The delta of an option contract that is listed on a regulated exchange described in paragraph (g)(4)(ii) of this section is the delta of that option at the close of business on the business day before the date of issuance. On the date an option contract is listed for the first time, the delta is the delta of that option at the close of business on the date of issuance. Notwithstanding the preceding two sentences, the delta of a listed option that is also a customized option is determined under the rules of paragraphs (g)(2) and (g)(3) of this section.

(ii) Regulated exchange. For purposes of paragraph (g)(4)(i) of this section, a regulated exchange is any exchange that is either:

(A) Described in paragraph (l)(3)(vii) of this section; or

(B) [Reserved]. For further guidance, see § 1.871–15T(g)(4)(ii)(B).

* * * * *

(h) Substantial equivalence test—(1) In general. The substantial equivalence test described in this paragraph (h) applies to determine whether a complex contract is a section 871(m) transaction. The substantial equivalence test assesses whether a complex contract substantially replicates the economic performance of the underlying security by comparing, at various testing prices for the underlying security, the differences between the expected changes in value of that complex contract and its initial hedge with the differences between the expected changes in value of a simple contract benchmark (as described in paragraph (h)(2) of this section) and its initial hedge. If the complex contract contains more than one reference to a single underlying security, all references to that underlying security are taken into account for purposes of applying the substantial equivalence test with respect to that underlying security. With respect to an equity derivative that is embedded in a debt instrument or other derivative, the substantial equivalence test is applied to the complex contract without taking into account changes in the market value of the debt instrument or other derivative that are not directly related to the equity element of the instrument. The complex contract is a section 871(m) transaction with respect to an underlying security if, for that underlying security, the expected change in value of the complex contract and its initial hedge is equal to or less than the expected change in value of the simple contract benchmark and its initial hedge when the substantial equivalence test described in this paragraph (h) is calculated at the calculation time for the complex contract. To the extent that the steps of the substantial equivalence test set out in this paragraph (h) cannot be applied to a particular complex contract, a taxpayer must use the principles of the substantial equivalence test to reasonably determine whether the complex contract is a section 871(m) transaction with respect to each underlying security. For purposes of this section, the test must be applied and the inputs must be determined in a commercially reasonable manner. The term of the simple contract benchmark must be, and the inputs must use, a reasonable time period, consistently applied (for example, in determining the standard deviation and probability). If a taxpayer calculates any relevant input for non-tax business purposes, that input ordinarily is the input used for purposes of this section.

(2) Simple contract benchmark. The simple contract benchmark is an actual or hypothetical simple contract that, at the calculation time for the complex contract, has a delta of 0.8, references the applicable underlying security referenced by the complex contract, and has terms that are consistent with all the material terms of the complex contract, including the maturity date. If an actual simple contract does not exist, the taxpayer must create a hypothetical simple contract. Depending on the complex contract, the simple contract benchmark might be, for example, a call option, a put option, or a collar.

(3) Substantial equivalence. A complex contract is a section 871(m) transaction with respect to an underlying security if the complex contract calculation described in paragraph (h)(4) of this section results in an amount that is equal to or less than the amount of the benchmark calculation described in paragraph (h)(5) of this section.

(4) Complex contract calculation—(i) In general. The complex contract calculation for each underlying security referenced by a potential section 871(m) transaction that is a complex contract is computed by:

(A) Determining the change in value (as described in paragraph (h)(4)(ii) of this section) of the complex contract with respect to the underlying security at each testing price (as described in paragraph (h)(4)(iii) of this section);

(B) Determining the change in value of the initial hedge for the complex contract at each testing price;

(C) Determining the absolute value of the difference between the change in value of the complex contract determined in paragraph (h)(4)(i)(A) of this section and the change in value of the initial hedge determined in paragraph (h)(4)(i)(B) of this section at each testing price;

(D) Determining the probability (as described in paragraph (h)(4)(iv) of this section) associated with each testing price;

(E) Multiplying the absolute value for each testing price determined in paragraph (h)(4)(i)(C) of this section by the corresponding probability for that testing price determined in paragraph (h)(4)(i)(D) of this section;

(F) Adding the product of each calculation determined in paragraph (h)(4)(i)(E) of this section; and

(G) Dividing the sum determined in paragraph (h)(4)(i)(F) of this section by the initial hedge for the complex contract.

(ii) Determining the change in value. The change in value of a complex contract is the difference between the value of the complex contract with respect to the underlying security at the calculation time for the complex contract and the value of the complex contract with respect to the underlying security if the price of the underlying security were equal to the testing price at the calculation time for the complex contract. The change in value of the initial hedge of a complex contract with respect to the underlying security is the difference between the value of the initial hedge at the calculation time for the complex contract and the value of the initial hedge if the price of the underlying security were equal to the testing price at the calculation time for the complex contract.

(iii) Testing price. The testing prices must include the prices of the underlying security if the price of the underlying security at the calculation time for the complex contract were alternatively increased by one standard deviation and decreased by one standard deviation, each of which is a separate testing price. In circumstances where using only two testing prices is reasonably likely to provide an inaccurate measure of substantial equivalence, a taxpayer must use additional testing prices as necessary to determine whether a complex contract satisfies the substantial equivalence test. If additional testing prices are used for the substantial equivalence test, the probabilities as described in paragraph (h)(4)(iv) of this section must be adjusted accordingly.

(iv) Probability. For purposes of paragraphs (h)(4)(i)(D) and (E) of this section, the probability of an increase by one standard deviation is the measure of the likelihood that the price of the underlying security will increase by any amount from its price at the calculation time for the complex contract. For purposes of paragraphs (h)(4)(i)(D) and (E) of this section, the probability of a decrease by one standard deviation is the measure of the likelihood that the price of the underlying security will decrease by any amount from its price at the calculation time for the complex contract.

(5) Benchmark calculation. The benchmark calculation with respect to each underlying security referenced by the potential section 871(m) transaction is determined by using the computation methodology described in paragraph (h)(4) of this section with respect to a simple contract benchmark for the underlying security.

(6) Substantial equivalence calculation for certain complex contracts that reference multiple underlying securities. If a complex contract references 10 or more underlying securities and an exchange-traded security (for example, an exchange-traded fund) is available that would fully hedge the complex contract at its calculation time, the substantial equivalence calculations for the complex contract may be calculated by treating the exchange-traded security as the underlying security. When the exchange-traded security is used for the substantial equivalence calculation pursuant to this paragraph (h)(6), the initial hedge is the number of shares of the exchange-traded security for purposes of calculating the amount of a dividend equivalent as provided in paragraph (j)(1)(iii) of this section.

(7) Example. The following example illustrates the rules of paragraph (h) of this section. For purposes of this example, Stock X is common stock of domestic corporation X. FI is the financial institution that structures the transaction described in the example, and is the short party to the transaction. Investor is a nonresident alien individual.

Example. Complex contract that is not substantially equivalent. (i) FI issues an investment contract (the Contract) that has a stated maturity of one year, and Investor purchases the Contract from FI at issuance for $10,000. At maturity, the Contract entitles Investor to a return of $10,000 (i) plus 200 percent of any appreciation in Stock X above $100 per share, capped at $110, on 100 shares or (ii) minus 100 percent of any depreciation in Stock X below $90 on 100 shares. At the calculation time for the Contract, the price of Stock X is $100 per share. Thus, for example, Investor will receive $11,000 if the price of Stock X is $105 per share at maturity of the Contract, but Investor will receive $9,000 if the price of Stock X is $80 per share when the Contract matures. At issuance, FI acquires 64 shares of Stock X to fully hedge the Contract issued to Investor. The calculation time for this example is the issuance.

(ii) The Contract references an underlying security and is not an NPC, so it is classified as an ELI under paragraph (a)(4) of this section. At the calculation time for the Contract, the Contract does not provide for an amount paid at maturity that is calculated by reference to a single, fixed number of shares of Stock X. When the Contract matures, the amount paid is effectively calculated based on either 200 shares of Stock X (if the price of Stock X has appreciated up to $110) or 100 shares of Stock X (if the price of Stock X has declined below $90). Consequently, the Contract is a complex contract described in paragraph (a)(14) of this section.

(iii) Because it is a complex ELI, FI applies the substantial equivalence test described in paragraph (h) of this section to determine whether the Contract is a specified ELI. FI determines that the price of Stock X would be $120 if the price of Stock X were increased by one standard deviation, and $79 if the price of Stock X were decreased by one standard deviation. Based on these results, FI next determines the change in value of the Contract to be $2000 at the testing price that represents an increase by one standard deviation ($12,000 testing price minus $10,000 issue price) and a negative $1,100 at the testing price that represents a decrease by one standard deviation ($10,000 issue price minus $8,900 testing price). FI performs the same calculations for the 64 shares of Stock X that constitute the initial hedge, determining that the change in value of the initial hedge is $1,280 at the testing price that represents an increase by one standard deviation ($6,400 at issuance compared to $7,680 at the testing price) and negative $1,344 at the testing price that represents a decrease by one standard deviation ($6,400 at issuance compared to $5,056 at the testing price).

(iv) FI then determines the absolute value of the difference between the change in value of the initial hedge and the Contract at the testing price that represents an increase by one standard deviation and a decrease by one standard deviation. Increased by one standard deviation, the absolute value of the difference is $720 ($2,000-$1,280); decreased by one standard deviation, the absolute value of the difference is $244 (negative $1,100 minus negative $1,344). FI determines that there is a 52% chance that the price of Stock X will have increased in value when the Contract matures and a 48% chance that the price of Stock X will have decreased in value at that time. FI multiplies the absolute value of the difference between the change in value of the initial hedge and the Contract at the testing price that represents an increase by one standard deviation by 52%, which equals $374.40. FI multiplies the absolute value of the difference between the change in value of the initial hedge and the Contract at the testing price that represents a decrease by one standard deviation by 48%, which equals $117.12. FI adds these two numbers and divides by the number of shares that constitute the initial hedge to determine that the transaction calculation is 7.68 ((374.40 plus 117.12) divided by 64).

(v) FI then performs the same calculation with respect to the simple contract benchmark, which is a one-year call option that references one share of Stock X, settles on the same date as the Contract, and has a delta of 0.8. The one-year call option has a strike price of $79 and has a cost (the purchase premium) of $22. The initial hedge for the one-year call option is 0.8 shares of Stock X.

(vi) FI first determines that the change in value of the simple contract benchmark is $19.05 if the testing price is increased by one standard deviation ($22.00 at issuance to $41.05 at the testing price) and negative $20.95 if the testing price is decreased by one standard deviation ($22.00 at issuance to $1.05 at the testing price). Second, FI determines that the change in value of the initial hedge is $16.00 at the testing price that represents an increase by one standard deviation ($80 at issuance to $96 at the testing price) and negative $16.80 at the testing price that represents a decrease by one standard deviation ($80.00 at issuance to $63.20 at the testing price).

(vii) FI determines the absolute value of the difference between the change in value of the initial hedge and the one-year call option at the testing price that represents an increase by one standard deviation is $3.05 ($16.00 minus $19.05). FI next determines the absolute value of the difference between the change in value of the initial hedge and the option at the testing price that represents a decrease by one standard deviation is $4.15 (negative $16.80 minus negative $20.95). FI multiplies the absolute value of the difference between the change in value of the initial hedge and the option at the testing price that represents an increase by one standard deviation by 52%, which equals $1.586. FI multiplies the absolute value of the difference between the change in value of the initial hedge and the option at the testing price that represents a decrease by one standard deviation by 48%, which equals $1.992. FI adds these two numbers and divides by the number of shares that constitute the initial hedge to determine that the benchmark calculation is 4.473 ((1.586 plus 1.992) divided by .8).

(viii) FI concludes that the Contract is not a section 871(m) transaction because the transaction calculation of 7.68 exceeds the benchmark calculation of 4.473.

(i) * * *

(3) * * * (ii) Publicly available dividend amount. For purposes of paragraph (i)(3)(i) of this section, if a section 871(m) transaction references the same underlying securities as a security (for example, stock in an exchange-traded fund) or index for which there is a publicly available quarterly dividend amount, the publicly available dividend amount may be used to determine the per-share dividend amount for the section 871(m) transaction with any adjustment for special dividends.

(iii) Dividend amount for a section 871(m) transaction using the simplified delta calculation. When the delta of a section 871(m) transaction is determined under paragraph (g)(3) of this section, the per-share dividend amount for that section 871(m) transaction must be determined using the dividend amount for the exchange-traded security that would fully hedge the section 871(m) transaction (whether or not the exchange-traded security is actually acquired).

* * * * *

(j) * * * (1) Calculation of the amount of a dividend equivalent. The long party is liable for tax on any dividend equivalents required to be determined pursuant to paragraph (j)(2) of this section only with respect to dividend equivalents that arise while the long party is a party to the transaction. The amount of any dividend equivalent is determined as follows:

* * * * *

(4) Taxable year of a dividend equivalent. A long party is liable for tax on a dividend equivalent in the year the dividend equivalent is subject to withholding pursuant to § 1.1441–2(e)(7). Notwithstanding the preceding sentence, a long party that is a qualified derivatives dealer is liable for tax on a dividend equivalent when the applicable dividend on the underlying security would be subject to withholding pursuant to § 1.1441–2(e)(4). The amount of the long party’s tax liability, however, is determined by reference to the amount that would have been due at the time the dividend equivalent amount is determined pursuant to paragraph (j)(2) of this section based on the beneficial owners at that time (for example, based on the tax rate at that time, whether the long party qualified for a treaty benefit at that time, and in the case of a partnership, based on the partners at that time).

* * * * *

(l) * * *

(2) Qualified index not treated as an underlying security—(i) In general. For purposes of this section, a qualified index is treated as a single security that is not an underlying security. The determination of whether an index referenced in a potential section 871(m) transaction is a qualified index is made at the calculation time for the transaction based on whether the index is a qualified index on the first business day of the calendar year containing the calculation time.

(ii) Rule for the first year of an index. In the case of an index that was not in existence on the first business day of the calendar year containing the calculation time for the transaction, paragraph (l)(2) of this section is applied by testing the index on the first business day it is created, and the dividend yield calculation required by paragraph (l)(3)(vi) of this section is determined by using the dividend yield that the index would have had in the immediately preceding year if it had the same components throughout that year that it has on the day it is created.

* * * * *

(4) Safe harbor for certain indices that reference assets other than underlying securities. Notwithstanding paragraph (l)(3) of this section, an index is a qualified index if the index is widely traded, the referenced component underlying securities in the aggregate comprise 10 percent or less of the weighting of the component securities in the index, and the index was not formed or availed of with a principal purpose of avoiding U.S. withholding tax.

* * * * *

(n) * * *

(3) Short party presumptions regarding combined transactions—(i) In general. If a short party relies on the presumption provided in paragraph (n)(3)(ii) of this section or in paragraph (n)(3)(iii) of this section, the short party is not required to treat those potential section 871(m) transactions as part of a single transaction pursuant to paragraph (n)(1) of this section.

* * * * *

(p) * * * (1) Responsible party—(i) In general. If a broker or dealer is a party to a potential section 871(m) transaction with a counterparty or customer that is not a broker or dealer, the broker or dealer is required to determine whether the potential section 871(m) transaction is a section 871(m) transaction. If both parties to a potential section 871(m) transaction are brokers or dealers, or neither party to a potential section 871(m) transaction is a broker or dealer, the short party must determine whether the potential section 871(m) transaction is a section 871(m) transaction.

(ii) [Reserved]. For further guidance, see § 1.871–15T(p)(1)(ii).

(iii) [Reserved]. For further guidance, see § 1.871–15T(p)(1)(iii).

(iv) [Reserved]. For further guidance, see § 1.871–15T(p)(1)(iv).

(v) Obligations of the responsible party. The party to the transaction that is required to determine whether a transaction is a section 871(m) transaction must also determine and report to the counterparty or customer the timing and amount of any dividend equivalent (as described in paragraphs (i) and (j) of this section). Except as otherwise provided in paragraph (n)(3) of this section, the party required to make the determinations described in this paragraph is required to exercise reasonable diligence to determine whether a transaction is a section 871(m) transaction, the amount of any dividend equivalents, and any other information necessary to apply the rules of this section. The information must be provided in the manner prescribed in paragraphs (p)(2) and (p)(3) of this section. The determinations required by paragraph (p) of this section are binding on the parties to the potential section 871(m) transaction and on any person who is a withholding agent with respect to the potential section 871(m) transaction unless the person knows or has reason to know that the information received is incorrect. The determinations are not binding on the Commissioner.

* * * * *

(4) * * *

(iii) Recordkeeping required for certain options. With respect to any option to which paragraph (g)(4) of this section applies, contemporaneous documentation is not required to be retained provided that there is a pre-existing documented methodology that is sufficient to permit the delta for the transaction to be verified at a later time.

(5) [Reserved]. For further guidance, see § 1.871–15T(p)(5).

(q) Dividend and dividend equivalent payments to a qualified derivatives dealer—(1) In general. Except as otherwise provided in this paragraph (q), a qualified derivatives dealer described in § 1.1441–1(e)(6) that receives a payment (within the meaning of paragraph (i) of this section) of a dividend equivalent in its equity derivatives dealer capacity will not be liable for tax under section 881 on that dividend equivalent, provided that the qualified derivatives dealer complies with its obligations under the qualified intermediary agreement described in §§ 1.1441–1(e)(5) and 1.1441–1(e)(6). A qualified derivatives dealer is liable for tax under section 881(a)(1) on its section 871(m) amount for each dividend on each underlying security. This tax liability is reduced (but not below zero) by the amount of tax paid by the qualified derivatives dealer under section 881(a)(1) on dividends it receives with respect to that underlying security on that same dividend in its capacity as an equity derivatives dealer. In addition, a qualified derivatives dealer is liable for tax under section 881(a)(1) for all dividend equivalents it receives that are not received in its equity derivatives dealer capacity. A qualified derivatives dealer also is liable for tax under section 881(a)(1) for all dividends it receives, other than dividends received in 2017 in its equity derivatives dealer capacity. This paragraph does not apply for a qualified derivatives dealer that is a foreign branch of a United States financial institution (within the meaning of § 1.1471–5(e)).

(2) Transactions on the books of an equity derivatives dealer. Transactions properly reflected in a qualified derivatives dealer’s equity derivatives dealer book are presumed to be held by the dealer in its equity derivatives dealer capacity for purposes of determining the qualified derivatives dealer’s tax liability. For purposes of determining whether a dealer is acting in its equity derivatives dealer capacity, only the dealer’s activities as an equity derivatives dealer are taken into account. Accordingly, for purposes of this paragraph (q), a dividend or dividend equivalent is treated as received by a qualified derivatives dealer acting in its non-equity derivatives dealer capacity if the dividend or dividend equivalent is received by a qualified derivatives dealer acting as a proprietary trader.

(3) Section 871(m) amount. For each dividend on each underlying security, the section 871(m) amount is the product of:

(4) Net delta exposure. The net delta exposure to an underlying security is the amount (measured in number of shares) by which (A) the aggregate number of shares of an underlying security that the qualified derivatives dealer has exposure to as a result of positions in the underlying security (including as a result of owning the underlying security) with values that move in the same direction as the underlying security (the long positions) exceeds (B) the aggregate number of shares of an underlying security that the qualified derivatives dealer has exposure to as a result of positions in the underlying security with values that move in the opposite direction from the underlying security (the short positions). The net delta exposure calculation only includes long positions and short positions that the qualified derivatives dealer holds in its equity derivatives dealer capacity (as described in paragraph (q)(2) of this section). Any long positions or short positions that are treated as effectively connected with the qualified derivatives dealer’s conduct of a trade or business in the United States for U.S. federal income tax purposes are excluded from the net delta exposure computation. The net delta exposure to an underlying security is determined at the end of the day on the date provided in § 1.871–15(j)(2) for the applicable dividend. For purposes of this calculation, net delta must be determined in a commercially reasonable manner. If a qualified derivatives dealer calculates net delta for non-tax business purposes, the net delta ordinary will be the delta used for that purpose, subject to the modifications required by this definition. Each qualified derivatives dealer must determine its net delta exposure separately only taking into account transactions that are recognized and are attributable to that qualified derivatives dealer for U.S. federal income tax purposes.

(5) Examples. The following examples illustrate the rules of this paragraph (q):

Example 1. Forward contract entered into by a foreign equity derivatives dealer. (i) Facts. FB is a foreign bank that is a qualified intermediary that acts as a qualified derivatives dealer. On April 1, Year 1, FB enters into a cash settled forward contract initiated by a foreign customer (Customer) that entitles Customer to receive from FB all of the appreciation and dividends on 100 shares of Stock X, and obligates Customer to pay FB any depreciation on 100 shares of Stock X, at the end of three years. FB hedges the forward contract by entering into a total return swap contract with a domestic broker (U.S. Broker) and maintains the swap contract as a hedge for the duration of the forward contract. The swap contract entitles FB to receive an amount equal to all of the dividends on 100 shares of Stock X and obligates FB to pay an amount referenced to a floating interest rate each quarter, and also entitles FB to receive from or pay to U.S. Broker, as the case may be, the difference between the value of 100 shares of Stock X at the inception of the swap and the value of 100 shares of Stock X at the end of 3 years. Stock X pays a quarterly dividend of $0.25 per share. At the end of the day on the date provided in paragraph (j)(2) of this section for the dividend, FB owns the forward contract and total return swap; FB does not own any shares of Stock X or any other transactions that reference Stock X. FB provides valid documentation to U.S. Broker that FB will receive payments under the swap contract in its capacity as a qualified derivatives dealer, and FB contemporaneously enters both the swap contract with U.S. Broker and the forward contract with Customer on its equity derivatives dealer books.

(ii) Application of rules. At the end of the day on the date provided in paragraph (j)(2) of this section for the dividend, FB is a long party on a delta one contract (the total return swap) and a short party on a delta one contract (the forward contract with Customer). Pursuant to § 1.1441–1(b)(4)(xxii), U.S. Broker is not obligated to withhold on the dividend equivalent payments to FB on the swap contract that are referenced to Stock X dividends because U.S. Broker has received valid documentation that it may rely upon to treat the payment as made to FB acting as a qualified derivatives dealer. Pursuant to paragraph (q)(1) of this section, FB is not liable for tax under sections 871(m) and 881 on the payments it receives from U.S. Broker referenced to Stock X dividends because FB’s net delta exposure with respect to 100 shares of Stock X is zero at the end of the day on the date provided in paragraph (j)(2) of this section for the dividend. The net delta exposure is zero because the taxpayer has 100 shares of Stock X long position exposure as a result of the total return swap that is reduced by 100 shares of Stock X short position exposure as a result of the forward contract. FB is required to withhold on dividend equivalent payments to Customer on the forward contract in accordance with § 1.1441–2(e)(7).

Example 2. At-the-money option contract entered into by a foreign equity derivatives dealer. (i) Facts. The facts are the same as Example 1, but Customer purchases from FB an at-the-money call option on 100 shares of Stock X with a term of one year. The call option has a delta of 0.5, and FB hedges the call option by entering into a total return swap that references 50 shares of Stock X with U.S. Broker. At the end of the day on the date provided in paragraph (j)(2) of this section for the dividend, the call option has a delta of 0.6, FB hedges the call option with a total return swap that references 60 shares of Stock X with U.S. Broker, and FB has no shares of Stock X or other transactions that reference Stock X.

(ii) Application of rules. At the end of the day on the date provided in paragraph (j)(2) of this section for the dividend, FB is a long party on 60 shares of Stock X through the total return swap and a short party on an option. Because the option has a delta of less than 0.8 at the calculation time, it is not a section 871(m) transaction. Therefore, there will be no dividend equivalent payments made by FB to Customer that are subject to withholding. Pursuant to § 1.1441–1(b)(4)(xxii), U.S. Broker is not obligated to withhold on the dividend equivalents with respect to Stock X paid to FB because U.S. Broker has received valid documentation that it may rely upon to treat the dividend equivalents as paid to FB acting as a qualified derivatives dealer. The net delta exposure is zero at the end of the day on the date provided in paragraph (j)(2) of this section for the dividend because FB has a long position of 60 shares as a result of the total return swap, which is reduced by FB’s short position of 60 shares as a result of the option.

Example 3. In-the-money option contract entered into by a foreign equity derivatives dealer. (i) Facts. The facts are the same as Example 2, but Customer purchases from FB an in-the-money call option on 100 shares of Stock X with a term of one year. The call option has a delta of 0.8 and FB hedges the call option by purchasing 80 shares of Stock X, which are held in an account with U.S. Broker, who also acts as paying agent. The price of Stock X declines substantially and the option lapses unexercised. At the end of the day on the date provided in paragraph (j)(2) of this section for the dividend, the call option has a delta of 0.48 and FB has reduced its hedge to 50 shares of Stock X with U.S. Broker. In addition, on that date, FB owns no other shares of Stock X or any other transactions that reference Stock X in its equity derivatives dealer capacity.

(ii) Application of rules. At the end of the day on the date provided in paragraph (j)(2) of this section for the dividend, FB is a long party on 50 shares of Stock X and a short party on an option. Because the option has a delta of 0.8 at the calculation time, it is a section 871(m) transaction. Therefore, FB is required to withhold on dividend equivalent payments to Customer on the option contract in accordance with § 1.1441–2(e)(7). U.S. Broker is required to withhold on the Stock X dividends paid to FB. Assuming that FB is a qualified resident of a country that provides withholding on dividends at a 15 percent rate, U.S. Broker is required withhold on the dividends with respect to the 50 shares of stock held by FB. FB’s net delta exposure is two shares of Stock X at the end of the day on the date provided in paragraph (j)(2) of this section because FB has a long position of 50 shares , reduced by FB’s short position of 48 shares as a result of the option. FB’s section 881 tax on the $0.50 (two shares multiplied by a dividend of $0.25 per share) is reduced (but not below zero) by the section 881 tax amount paid by qualified derivatives dealer on the 50 shares. Therefore, FB’s section 871(m) amount is zero.

(r) * * *

(3) Effective/applicability date for paragraphs (d)(2) and (e). Paragraphs (d)(2) and (e) of this section apply to any payment made on or after January 1, 2017, with respect to any transaction with a delta of one issued on or after January 1, 2017. Paragraphs (d)(2) and (e) of this section apply to any payment made on or after January 1, 2018, with respect to any other transaction issued on or after January 1, 2018. Notwithstanding the prior sentence, paragraphs (d)(2) and (e) of this section will apply to any payments made on or after January 1, 2020, with respect to the exchange-traded notes issued on or after January 1, 2017, that are identified in a separate notice, and not payments made before January 1, 2020, with respect to those notes. Notwithstanding the first sentence of this paragraph (r)(3), paragraphs (d)(2) and (e) of this section do not apply to payments made in 2017 to a qualified derivatives dealer in its equity derivatives dealer capacity to hedge transactions that have a delta of less than one.

(4) Effective/applicability date for paragraphs (c)(2)(iv), (h), and (q) of this section. Paragraphs (c)(2)(iv), (h), and (q) of this section apply to payments made on or after January 1, 2017.

(5) Effective/applicability date for paragraphs (g)(4)(ii)(B), (p)(1)(ii) through (iv), and (p)(5) of this section. [Reserved]. For further guidance, see § 1.871–15T(r)(5).

Par. 3. For each section listed in the table, remove the language in the “Remove” column and add in its place the language in the “Add” column as set forth below:

Par. 4. Revise § 1.871–15T to read as follows:

(a) [Reserved]. For further guidance, see § 1.871–15(a).

(1) Broker. A broker is a broker within the meaning provided in section 6045(c), except that the term does not include any corporation that is a broker solely because it regularly redeems its own shares.

(a)(2) through (g)(4)(ii)(A) [Reserved]. For further guidance, see § 1.871–15(a)(2) through (g)(4)(ii)(A).

(B) A foreign securities exchange that:

(1) Is regulated or supervised by a governmental authority of the country in which the market is located;

(2) Has trading volume, listing, financial disclosure, surveillance, and other requirements designed to prevent fraudulent and manipulative acts and practices, to remove impediments to and perfect the mechanism of a free and open, fair and orderly market, and to protect investors, and the laws of the country in which the exchange is located and the rules of the exchange ensure that those requirements are actually enforced;

(3) Has rules that effectively promote active trading of listed options on the exchange; and

(4) Has an average daily trading volume on the exchange exceeding $10 billion during the immediately preceding calendar year. If an exchange in a foreign country has more than one tier or market level on which listed options may be separately listed or traded, each tier or market level is treated as a separate exchange.

(g)(5) through (p)(1)(i) [Reserved]. For further guidance, see § 1.871–15(g)(5) through (p)(1)(i).

(ii) Transactions with multiple brokers. For a potential section 871(m) transaction in which both the short party and an agent or intermediary acting on behalf of the short party are a broker or dealer, the short party must determine whether the potential section 871(m) transaction is a section 871(m) transaction. For a potential section 871(m) transaction in which the short party is not a broker or dealer and more than one agent or intermediary acting on behalf of the short party is a broker or dealer, the broker or dealer that is a party to the transaction and closest to the short party in the payment chain must determine whether the potential section 871(m) transaction is a section 871(m) transaction. For a potential section 871(m) transaction in which neither the short party nor any agent or intermediary acting on behalf of the short party is a broker or dealer, and the long party and an agent or intermediary acting on behalf of the long party are a broker or dealer, or more than one agent or intermediary acting on behalf of the long party is a broker or dealer, the broker or dealer that is a party to the transaction and closest to the long party in the payment chain must determine whether the potential section 871(m) transaction is a section 871(m) transaction.

(iii) Responsible party for transactions traded on an exchange and cleared by a clearing organization. Except as provided in paragraph (p)(1)(iv) of this section, for a potential section 871(m) transaction that is traded on an exchange and cleared by a clearing organization, and for which more than one broker-dealer acts as an agent or intermediary between the short party and a foreign payee, the broker or dealer that has an ongoing customer relationship with the foreign payee with respect to that transaction (generally the clearing firm) must determine whether the potential section 871(m) transaction is a section 871(m) transaction.

(iv) Responsible party for certain structured notes, warrants, and convertible instruments. When a potential section 871(m) transaction is a structured note, warrant, convertible stock, or convertible debt, the issuer is the party responsible for determining whether a potential section 871(m) transaction is a section 871(m) transaction.

(p)(1)(v) through (p)(4) [Reserved]. For further guidance, see § 1.871–15(p)(1)(v) through (p)(4).

(5) Example. The following example illustrates the rules of paragraph (p) of this section:

Example 1. CO is a domestic clearing organization and is not a broker as defined in § 1.871–15(a)(1). CO serves as a central counterparty clearing and settlement service provider for derivatives exchanges in the United States. EB and CB are brokers organized in the United States and members of CO. FC, a foreign corporation, instructs EB to execute the purchase of a call option that is a specified ELI (as described in § 1.871–15(e)). EB effects the trade for FC on the exchange and then, as instructed by FC, transfers the option to CB to be cleared with CO. The exchange matches FC’s order with an order for a written call option with the same terms and then sends the matched trade to CO, which clears the trade. CB and the clearing member representing the person who sold the call option settle the trade with CO. Upon receiving the matched trade, the option contracts are novated and CO becomes the counterparty to CB and the counterparty to the clearing member representing the person who sold the call option. Both EB and CB are broker-dealers acting on behalf of FC for a potential section 871(m) transaction. Under paragraph (p)(1)(iii) of this section, however, only CB is required to make the determinations described in § 1.871–15(p).

(q) through (r)(4) [Reserved]. For further guidance, see § 1.871–15(r)(1) through (4).

(5) Effective/applicability date. This section applies to payments made on or after on January 19, 2017.

(s) Expiration date. This section expires January 17, 2020.

Par. 5. Section 1.1441–1 is amended by:

1. Revising paragraphs (b)(4)(xxii), (e)(3)(ii)(E), (e)(5),and (e)(6).

2. Adding a new sentence to the end of paragraph (e)(2)(i).

3. Adding new paragraph (f)(5).

The additions and revisions read as follows:

* * * * *

(b) * * *

(4) * * *

(xxii) Certain payments to qualified derivatives dealers (as described in paragraph (e)(6) of this section). For purposes of this withholding exemption, the qualified derivatives dealer must furnish to the withholding agent the documentation described in paragraph (e)(3)(ii) of this section. A withholding agent that makes a payment to a qualified intermediary that is acting as a qualified derivatives dealer is not required to withhold on the following payments if the withholding agent can reliably associate the payment with a valid qualified intermediary withholding certificate as described in paragraph (e)(3)(ii) of this section, including the certification described in paragraph (e)(3)(ii)(E):

(A) A payment with respect to a potential section 871(m) transaction that is not an underlying security;

(B) A payment of a dividend equivalent; or

(C) A payment of a dividend in 2017.

* * * * *

(e) * * *

(2) * * *

(i) * * * For purposes of a qualified intermediary acting as a qualified derivatives dealer, a qualified intermediary withholding certificate, as described in paragraph (e)(3)(ii) of this section is a beneficial owner withholding certificate for purposes of treaty claims for dividends.

* * * * *

(3) * * *

(ii) * * *

(E) In the case of any payment with respect to a potential section 871(m) transaction (including any dividend equivalent payment within the meaning of § 1.871–15(i)) or underlying security (as defined in § 1.871–15(a)(15)) received by a qualified intermediary acting as a qualified derivatives dealer, a certification that the home office or branch receiving the payment, as applicable, meets the requirements to act as a qualified derivatives dealer as further described in paragraph (e)(6) of this section and that the qualified derivatives dealer assumes primary withholding and reporting responsibilities under chapters 3, 4, and 61, and section 3406 with respect to any payments it makes with respect to potential section 871(m) transactions;

* * * * *

(5) Qualified intermediaries—(i) In general. A qualified intermediary, as defined in paragraph (e)(5)(ii) of this section, may furnish a qualified intermediary withholding certificate to a withholding agent. The withholding certificate provides certifications on behalf of other persons for the purpose of claiming and verifying reduced rates of withholding under section 1441 or 1442 and for the purpose of reporting and withholding under other provisions of the Code, such as the provisions under chapter 61 and section 3406 (and the regulations under those provisions), or for the qualified derivative dealer (if applicable). Furnishing such a certificate is in lieu of transmitting to a withholding agent withholding certificates or other appropriate documentation for the persons for whom the qualified intermediary receives the payment, including interest holders in a qualified intermediary that is fiscally transparent under the regulations under section 894. Although the qualified intermediary is required to obtain withholding certificates or other appropriate documentation from beneficial owners, payees, or interest holders pursuant to its agreement with the IRS, it is generally not required to attach such documentation to the intermediary withholding certificate. Notwithstanding the preceding sentence, a qualified intermediary must provide a withholding agent with the Forms W–9, or disclose the names, addresses, and taxpayer identifying numbers, if known, of those U.S. non-exempt recipients for whom the qualified intermediary receives reportable amounts (within the meaning of paragraph (e)(3)(vi) of this section) to the extent required in the qualified intermediary’s agreement with the IRS. When a qualified intermediary is acting as a qualified derivatives dealer, the withholding certificate entitles a withholding agent to make payments with respect to potential section 871(m) transactions that are not underlying securities and dividend equivalent payments on underlying securities to the qualified derivatives dealer free of withholding. A withholding agent is required to withhold on all other U.S. source FDAP payments made to a qualified derivatives dealer as required by applicable law. Paragraph (e)(6) of this section contains detailed rules prescribing the circumstances in which a qualified intermediary can act as a qualified derivatives dealer. A person may claim qualified intermediary status before an agreement is executed with the IRS if it has applied for such status and the IRS authorizes such status on an interim basis under such procedures as the IRS may prescribe.

(ii) [Reserved]. For additional guidance, see § 1.1441–1T(e)(5)(ii).

(A) Through (C) [Reserved]. For additional guidance, see § 1.1441–1T(e)(5)(ii)(A)–(C).

(D) A foreign person that is a home office or has a branch that is an eligible entity as described in paragraph (e)(6)(ii) of this section, without regard to the requirement that the person be a qualified intermediary; or

(E) [Reserved]. For additional guidance, see § 1.1441–1T(e)(5)(ii)(E).

(iii) [Reserved]. For additional guidance, see § 1.1441–1T(e)(5)(iii).

(iv) [Reserved]. For additional guidance, see § 1.1441–1T(e)(5)(iv).

(v) [Reserved]. For additional guidance, see § 1.1441–1T(e)(5)(v).

(A) [Reserved]. For additional guidance, see § 1.1441–1T(e)(5)(v)(A).

(B) [Reserved]. For additional guidance, see § 1.1441–1T(e)(5)(v)(B).

(1) – (3) [Reserved]. For additional guidance, see § 1.1441–1T(e)(5)(v)(B)(1)–(3).

(4) If a qualified intermediary is acting as a qualified derivatives dealer, designate the accounts:

(i) For which the qualified derivatives dealer is receiving payments with respect to potential section 871(m) transactions or underlying securities as a qualified derivatives dealer;

(ii) For which the qualified derivatives dealer is receiving payments with respect to potential section 871(m) transactions (and that are not underlying securities) for which withholding is not required;

(iii) For which qualified derivatives dealer is receiving payments with respect to underlying securities for which withholding is required; and

(iv) If applicable, identifying the home office or branch that is treated as the owner for U.S. income tax purposes; and

(6) Qualified derivatives dealers—(i) In general. To act as a qualified derivatives dealer under a qualified intermediary withholding agreement, the home office or branch that is a qualified intermediary must be an eligible entity as described in paragraph (e)(6)(ii) of this section and, in accordance with the qualified intermediary agreement, must—

(A) Furnish to a withholding agent a qualified intermediary withholding certificate (described in paragraph (e)(3)(ii) of this section) that indicates that the home office or branch receiving the payment is a qualified derivatives dealer with respect to the payments associated with the withholding certificate;

(B) Agree to assume the primary withholding and reporting responsibilities, including the documentation provisions under chapters 3, 4, and 61, and section 3406, the regulations under those provisions, and other withholding provisions of the Internal Revenue Code, for payments made as a qualified derivatives dealer with respect to potential section 871(m) transactions. For this purpose, a qualified derivatives dealer is required to obtain a withholding certificate or other appropriate documentation from each counterparty to whom the qualified derivatives dealer makes a reportable payment (including a dividend equivalent payment within the meaning of § 1.871–15(i)). The qualified derivatives dealer is also required to determine whether any payment it makes with respect to a potential section 871(m) transaction is, in whole or in part, a dividend equivalent;

(C) Agree to remain liable for tax under section 881, if any, on any payment with respect to a potential section 871(m) transaction (including a dividend equivalent payment within the meaning of § 1.871–15(i)) and underlying securities (including dividends) it receives as a qualified derivatives dealer, or in the case of dividend equivalents received in the equity derivatives dealer capacity, the taxes required pursuant to § 1.871–15(q);

(D) Comply with the compliance review procedures applicable to a qualified intermediary that acts as a qualified derivatives dealer under the qualified intermediary withholding agreement, which will specify the time and manner in which a qualified derivatives dealer must:

(1) Certify to the IRS that it has complied with the obligations to act as a qualified derivatives dealer (including its performance of a periodic review applicable to a qualified derivatives dealer);

(2) Report to the IRS any amounts subject to reporting on Forms 1042–S (including dividend equivalent payments that it made);

(3) Report to the IRS on the appropriate U.S. tax return, its tax liabilities, including its tax liability pursuant to § 1.871–15(q)(1) and any other taxes on payments with respect to potential section 871(m) transactions or underlying securities as defined in § 1.871–15(a)(15) it receives; and

(4) Respond to inquiries from the IRS about obligations it has assumed as a qualified derivatives dealer in a timely manner;

(E) Agree to act as a qualified derivatives dealer for all payments made as a principal with respect to potential section 871(m) transactions and all payments received as a principal with respect to potential section 871(m) transactions and underlying securities as defined in § 1.871–15(a)(15) (including dividend equivalent payments within the meaning of § 1.871–15(i)), excluding any payments made or received by the qualified derivatives dealer to the extent the payment is treated as effectively connected with the conduct of a trade or business within the United States within the meaning of section 864, and not act as a qualified derivatives dealer for any other payments. For purposes of this paragraph (E), any securities lending or sale-repurchase transaction that the qualified intermediary enters into that is a section 871(m) transaction is treated as entered into as a principal unless the qualified intermediary determines that it is acting as an intermediary with respect to that transaction; and

(F) Each home office or branch must qualify and be approved for qualified derivatives dealer status and must represent itself as a QDD on its Form W–8IMY and separately identify the home office or branch as the recipient on a withholding statement (if necessary). The home office means a foreign person, excluding any branches of the foreign person, that applies for qualified derivatives dealer status. Each home office or branch that obtains qualified derivatives dealer status must be treated as a separate qualified derivatives dealer.

(ii) Definition of eligible entity. An eligible entity is a home office or branch that is a qualified intermediary and that, treating the home office or branch as a separate entity, is—

(A) An equity derivatives dealer subject to regulatory supervision as a dealer by a governmental authority in the jurisdiction in which it was organized or operates;

(B) A bank or bank holding company subject to regulatory supervision as a bank or bank holding company (as applicable) by a governmental authority in the jurisdiction in which it was organized, or operates or an entity that is wholly-owned (directly or indirectly) by a bank or bank holding company subject to regulatory supervision as a bank or bank holding company (as applicable) by a governmental authority in the jurisdiction in which the bank or bank holding company (as applicable) was organized or operates and that in its equity derivatives dealer capacity—

(1) Issues potential section 871(m) transactions to customers; and

(2) Receives dividends with respect to stock or dividend equivalent payments pursuant to potential section 871(m) transactions that hedge potential section 871(m) transactions that it issued;

(C) A foreign branch of a U.S. financial institution, if the foreign branch would meet the requirements of paragraph (A) or (B) of this section if it were a separate entity; or

(D) Any person otherwise acceptable to the IRS.

* * * * *

(f) * * *

(5) Effective/applicability date. Paragraphs (e)(5)(ii)(D) and (e)(5)(v)(B)(4) of this section apply to payments made on or after on January 19, 2017.

Par. 6. Section 1.1441–1T is amended by:

1. Redesignating paragraph (e)(5)(ii)(D) as paragraph (e)(5)(ii)(E), redesignating paragraph (e)(5)(v)(B)(4) as paragraph (e)(5)(v)(B)(5) and adding new paragraphs (e)(5)(ii)(D) and (e)(5)(v)(B)(4).

2. Revising paragraphs (e)(3)(ii)(E), (e)(5)(i), (e)(5)(v)(B)(4), and (e)(6).

3. Removing the language “Except for paragraphs (e)(3)(ii)(E) and (e)(6), this section” from the first sentence of paragraph (f)(3) and adding in its place “This section”, and removing the third sentence in paragraph (f)(3), and

4. Removing the language “Except for paragraphs (e)(3)(ii)(E) and (e)(6), the applicability” from the first sentence of paragraph (g) and adding in its place “The Applicability” and removing the second sentence in paragraph (g).

* * * * *

(e) * * *

(3) * * *

(ii) * * *

(E) [Reserved]. For additional guidance, see § 1.1441–1(e)(3)(ii)(E).

* * * * *

(5) Qualified Intermediaries—(i) [Reserved]. For additional guidance, see § 1.1441–1(e)(5)(i).

(ii) * * *

(D) [Reserved]. For additional guidance, see § 1.1441–1(e)(5)(ii)(D).

* * * * *

(v) * * *

(B) * * *

(4) [Reserved]. For additional guidance, see § 1.1441–1(e)(5)(v)(B)(4).

* * * * *

(6) [Reserved]. For additional guidance, see § 1.1441–1(e)(6).

* * * * *

Par. 7. Section 1.1441–2 is amended by:

1. Revising paragraphs (e)(7)(i) and (e)(7)(ii).

2. Removing “paragraph (e)(8)(ii)(A)” from paragraph (e)(7)(iii) and adding in “paragraph (e)(7)(ii)(A)” in its place.

3. Adding paragraphs (e)(7)(iv) through (ix).

4. Revising the last sentence of paragraph (f)(1) and adding a new last sentence.

The revisions and additions read as follows:

* * * * *

(e) * * *

(7) Payments of dividend equivalents—(i) In general. Subject to paragraphs (e)(7)(iv), (vi), and (vii) of this section, a payment of a dividend equivalent is not considered to be made until the later of when—

(A) The amount of a dividend equivalent is determined as provided in § 1.871–15(j)(2), and

(B) A payment occurs with respect to the section 871(m) transaction after the amount of a dividend equivalent is determined as provided in § 1.871–15(j)(2).

(ii) Payment. For purposes of paragraph (e)(7) of this section, a payment occurs with respect to a section 871(m) transaction when—

(A) Money or other property is paid to or by the long party, unless the section 871(m) transaction is described in § 1.871–15(i)(3), in which case a payment is treated as being made at the end of the applicable calendar quarter;

(B) The long party sells, exchanges, transfers, or otherwise disposes of the section 871(m) transaction (including by settlement, offset, termination, expiration, lapse, or maturity); or

(C) The section 871(m) transaction is transferred to an account that is not maintained by the withholding agent or the long party terminates the account relationship with the withholding agent.

* * * * *

(iv) Option to withhold on dividend payment date. A withholding agent may withhold on the payment date described in paragraph (e)(4) of this section for the applicable dividend on the underlying security (the dividend payment date) if it withholds on that date for all section 871(m) transactions of the same type (securities lending or sale-repurchase transaction, NPC, or ELI) and satisfies the requirements to paragraph (e)(7)(v) of this section.

(v) Changes to time of withholding. This paragraph describes how a withholding agent changes the time that it withholds on a dividend equivalent payment to a time described in paragraph (e)(7)(i) or (iv) of this section and these requirements must be satisfied for a withholding agent to change the time it withholds. A withholding agent must apply the change consistently to all transactions of the same type entered into on or after the change. For transactions of the same type entered into before the change, a withholding agent must withhold under the original approach throughout the term of the transaction. When a withholding agent changes the time that it will withhold, the withholding agent must notify each payee in writing that it will withhold using the approach described in paragraph (e)(7)(i) or (iv) of this section, as applicable, before the time for determining the payee’s first dividend equivalent payment (as determined under § 1.871–15(j)(2)). With respect to transactions held by an intermediary or foreign flow-through entity, a withholding agent is treated as providing notice to each payee holding that transaction through the entity when it notifies the intermediary or foreign flow-through entity of the time it will withhold, as described in the preceding sentence, provided that the intermediary or foreign flow-through entity agrees to provide the same notice to each payee. The withholding agent must attach a statement to its relevant income tax return (filed by the due date, including extensions) for the year of the change notifying the IRS of the change and when it applies, identifying the types of section 871(m) transaction to which the change applies, and certifying that has notified its payees. For purposes of this paragraph, a withholding agent will be considered to have entered into a transaction on the first date the withholding agent becomes responsible for withholding on the transaction (based on the rule in paragraph (e)(7)(ix) of this section).

(vi) Withholding by qualified derivatives dealers. A withholding agent that is acting as a qualified derivatives dealer must withhold with respect to a dividend equivalent payment on the payment date described in paragraph (e)(4) of this section for the applicable dividend on the underlying security and must notify each payee in writing that it will withhold on the dividend payment date before the time for determining the payee’s first dividend equivalent payment (as determined under § 1.871–15(j)(2)).

(vii) Withholding with respect to derivatives that reference partnerships. To the extent that a withholding agent is required to withhold with respect to a partnership interest described in § 1.871–15(m), the liability for withholding arises on March 15 of the year following the year in which the payment of a dividend equivalent (determined under § 1.871–15(i)) occurs.

(viii) Notification to holders of withholding timing. If a withholding agent is required to notify a payee of when it will withhold under paragraph (e)(7)(v) of this section, it may use the reporting methods prescribed in § 1.871–15(p)(3)(i).

(ix) Withholding agent responsibility. A withholding agent is only responsible for dividend equivalent amounts determined (as provided in § 1.871–15(j)(2)) during the period the withholding agent is a withholding agent for the section 871(m) transaction.

* * * * *

(f) * * * (1) Except as otherwise provided in this paragraph, paragraph (e)(7) of this section applies to payments made on or after September 18, 2015. Paragraphs (e)(7)(ii)(D) and (e)(7)(iv) through (viii) of this section apply to payments made on or after January 19, 2017.

Par. 8. Section 1.1441–7 is amended by:

1. Revising Example 7 in paragraph (a)(3).

2. Adding Example 8 and 9 to paragraph (a)(3).

3. Adding a sentence to the end of paragraph (a)(4).

The additions read as follows:

(a) * * *

(3) * * *

Example 7. CO is a domestic clearing organization. CO serves as a central counterparty clearing and settlement service provider for derivatives exchanges in the United States. CB is a broker organized in Country X, a foreign country, and a clearing member of CO. CB is a nonqualified intermediary, as defined in § 1.1441–1(c)(14). FC is a foreign corporation that has an account with CB. FC instructs CB to purchase a call option that is a specified ELI (as described in § 1.871–15(e)). CB effects the trade for FC on the exchange. The exchange matches FC’s order with an order for a written call option with the same terms. The exchange then sends the matched trade to CO, which clears the trade. CB and the clearing member representing the person who sold the call option settle the trade with CO. Upon receiving the matched trade, the option contracts are novated and CO becomes the counterparty to CB and the counterparty to the clearing member representing the person who sold the call option. To the extent that there is a dividend equivalent with respect to the call option, both CO and CB are withholding agents as described in paragraph (a)(1) of this section. As a withholding agent, CO and CB must each determine whether it is obligated to withhold under chapter 3 of the Internal Revenue Code and the regulations thereunder.

Example 8. FCO is a foreign clearing organization. FCO serves as a central counterparty clearing and settlement service provider for derivatives exchanges in Country A, a foreign country. CB is a broker organized in Country A, and a clearing member of FCO. CB is a nonqualified intermediary, as defined in § 1.1441–1(c)(14). FC is a foreign corporation that has an account with CB. FC instructs CB to purchase a call option that is a section 871(m) transaction. CB effects the trade for FC on the exchange. The exchange matches FC’s order with an order for a written call option with the same terms. The exchange then sends the matched trade to FCO, which clears the trade. CB and the clearing member representing the call option seller settle the trade with FCO. Upon receiving the matched trade, the option contracts are novated and FCO becomes the counterparty to CB and the counterparty to the clearing member representing the call option seller. To the extent that there is a dividend equivalent with respect to the call option, both FCO and CB are withholding agents as described in paragraph (a)(1) of this section.

Example 9. The facts are the same as Example 8, except that CB is a qualified intermediary, as defined in § 1.1441–1(c)(15), that has assumed the primary obligation to withhold, deposit, and report amounts under chapters 3 and 4 of Internal Revenue Code. CB provides a written statement to FCO representing that it has assumed primary withholding responsibility for any dividend equivalent payment with respect to the call option. FCO, therefore, is not required withhold on a dividend equivalent payment to CB.

(4) * * * Example 8 and Example 9 of paragraph (a)(3) of this section apply to payments made on or after January 19, 2017.

* * * * *

These final regulations prescribe a uniform framework for determining which mineral and natural resource activities generate qualifying income based on the statutory language and congressional intent as interpreted by the Treasury Department and the IRS. In relevant part, section 7704(d)(1)(E) provides merely that “income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy, and timber)” is qualifying income. The limited statutory text supplies only one relevant definition—for “mineral or natural resource.” See section 7704(d)(1). The legislative history regarding the specific text at issue is likewise brief and susceptible to different interpretations, as demonstrated by the comment letters received.

Although the statute and the legislative history do not provide definitions or a clear demarcation of the eight active terms and industry experts disagree on the scope of these terms, certain guiding principles can be gleaned. First, the Treasury Department and the IRS regard as particularly significant the fact that Congress passed section 7704 in whole to restrict the growth of PTPs, which it viewed as eroding the corporate tax base. See H.R. Rep. No. 100–391, at 1065 (1987) (“The recent proliferation of publicly traded partnerships has come to the committee’s attention. The growth in such partnerships has caused concern about long-term erosion of the corporate tax base.”) Congress expressed alarm that the changes enacted in the Tax Reform of Act of 1986 that reflected their intent to preserve the corporate level of tax were “being circumvented by the growth of publicly traded partnerships that are taking advantage of an unintended opportunity for disincorporation and elective integration of the corporate and shareholder levels of tax.” Id. at 1066. Congress made an exception for passive-type income and “certain types of natural resources” because “special considerations appl[ied].” Id. at 1066, 1069. Well-established statutory construction principles direct that, because section 7704(d)(1)(E) was an exception to the general rule, it should be read narrowly. See, for example, Comm’r v. Jacobson, 336 U.S. 28, 49 (1949) (“The income taxed is described in sweeping terms and should be broadly construed in accordance with an obvious purpose to tax income comprehensively. The exemptions, on the other hand, are specifically stated and should be construed with restraint in the light of the same policy.”).

Second, the eight listed active terms in section 7704(d)(1)(E) represent stages in the extraction of minerals or natural resources and the eventual offering of certain products for sale. A mineral or natural resource may be explored for and, if found, is developed, mined or produced, processed, refined, transported, and ultimately marketed. Manufacturing is not an activity referenced in the statute, although as some might argue, processing and refining are forms of manufacturing. The omission of manufacturing is significant especially in light of other directives from the legislative history. Most importantly, the Conference Committee Report provides, by example, an endpoint to activities the income from which would be qualifying, by indicating that “[o]il, gas, or products thereof are not intended to encompass oil or gas products that are produced by additional processing beyond that of petroleum refineries or field facilities, such as plastics or similar petroleum derivatives.” H.R. Rep. No. 100–495, at 947 (1987). The Treasury Department and the IRS have interpreted this language to mean that Congress did not intend to include extended processing or manufacturing activities beyond getting an extracted mineral or natural resource to market in a form in which those products are generally sold.

This interpretation is reinforced by Congress’s explanation in the legislative history that natural resources were granted an exception to the general rule of corporate taxation in section 7704 because the activities in those industries “have commonly or typically been conducted in partnership form, and the committee considers that disruption of present practices in such activities is currently inadvisable due to general economic conditions in these industries.” H.R. Rep. No. 100–391, at 1066 (1987). The committees responsible for drafting the legislation had previously held three days of hearings dedicated to reviewing the use and taxation of master limited partnerships (MLPs), another term for PTPs, and heard multiple witnesses discuss the use of partnerships and joint ventures to raise capital for oil and gas exploration, the difference between investing in wasting natural resource assets and investing in active businesses, the price of commodities, and the importance of natural resource development to the nation’s security. See, for example, Master Limited Partnerships: Hearings Before the H. Subcomm. on Select Revenue Measures of the Comm. on Ways and Means, 100th Cong. 10 and 189 (1987) (statement of J. Roger Mentz, Asst. Sec. for Tax Policy, U.S. Dep’t of the Treasury, expressing concern that the rise in MLPs was “not limited to passive ownership or wasting assets such as oil and gas or natural resource properties,” but instead were “increasingly being used for active business enterprises,” and statement of Christopher L. Davis, President, Investment Partnership Association, explaining that “[o]il and gas exploration and development are among the riskiest of business ventures,” but that partnerships had been “an economical way to share the risks”). See also Master Limited Partnerships: Hearing before the S. Subcomm. on Taxation and Debt Management of the Comm. on Finance, 100th Cong. 90 (1987) (statement of James R. Moffett, CEO, Freeport-McMoran, Inc., stating that the “commodities in this country have been decimated” and that the mining and natural resources businesses must be completely rebuilt). There was no testimony about the need to protect manufacturing industries.

These principles have informed the scope and approach of these final regulations and the responses to commenters in this Summary of Comments and Explanation of Revisions. The Treasury Department and the IRS have concluded that in using general terms without technical definitions, Congress did not intend a uniform definition of such terms across all minerals and natural resources. Rather, Congress meant to capture those activities customary to each industry that move a depletable asset to a point at which it is commonly sold, and did not mean to include those activities that create a new or different product through further, extended processing or manufacturing. Accordingly, these final regulations describe as qualifying income the income and gains from the activities performed to produce products typically found at field facilities and petroleum refineries or the equivalent for other natural resources, certain transportation and marketing activities with respect to those products, and intrinsic service activities that are specialized, essential, and require significant services with respect to exploration, development, mining and production, processing, refining, transportation, and marketing.

In section 7704(d)(1), Congress defined the term “mineral or natural resource” as “any product of a character with respect to which a deduction for depletion is allowable under section 611; except that such term shall not include any product described in subparagraph (A) or (B) of section 613(b)(7).” Products described in section 613(b)(7)(A) and (B) are soil, sod, dirt, turf, water, mosses, and minerals from sea water, the air, or other similar inexhaustible sources. The proposed regulations adopted, almost verbatim, this same definition, but also specifically included fertilizer, geothermal energy, and timber in the definition of mineral or natural resource, and explained that the regulations did not address industrial source carbon dioxide, fuels described in section 6426(b) through (e), any alcohol fuel defined in section 6426(b)(4)(A), or any biodiesel fuel as defined in section 40A(d)(1).

Many commenters recommended that the definition of mineral or natural resource be expanded to include not only products of a character with respect to which a deduction for depletion is allowable under section 611, but also “products thereof.” These commenters believed Congress intended the definition of mineral or natural resource to be read expansively, citing to the 1987 legislative history, which provides that: “[N]atural resources include fertilizer[,] geothermal energy, and timber, as well as oil, gas or products thereof. . . . For this purpose, oil, gas, or products thereof means gasoline, kerosene, number 2 fuel oil, refined lubricating oils, diesel fuel, methane, butane, propane, and similar products which are recovered from petroleum refineries or field facilities.” H.R. Rep. No. 100–495, at 946-947 (1987). The significance of these commenters’ expansive definition is that, under this view, so long as a product was depletable at the time of its production or extraction, it remains a “product thereof” throughout its processing, refining, transportation, and marketing. Under this theory, a depletable product does not lose its status as a mineral or natural resource by being processed or refined, and can therefore be further processed or refined without limitation.

These final regulations do not adopt this recommendation. As originally passed in 1987, section 7704(d)(1)(E) did not define the term mineral or natural resource. Congress added the definition in 1988 (one year after the 1987 legislative history cited by the commenters) as part of the Technical and Miscellaneous Revenue Act of 1988. It is that same statutory definition added by Congress that these final regulations adopt almost word for word. Moreover, in the statutory text, the phrase “products thereof” is used only in a parenthetical describing transportation. See section 7704(d)(1)(E) (“income and gains derived from the . . . transportation (including pipelines transporting gas, oil, or products thereof)”). The 1988 legislative history likewise used the phrase “products thereof” in a limited manner, that is only when describing transportation and marketing. See, for example, H.R. Rep. No. 100–1104(II), at 17 (1988) (“In the case of transportation activities with respect to oil and gas and products thereof”) and S. Rep. 100–445, at 424 (1988) (“With respect to the marketing of minerals and natural resources (e.g., oil and gas and products therefof [sic])”). Finally, defining mineral and natural resource without including products thereof is the most logical interpretation of the statute, taking into account the enumerated activities the statute contemplates to be undertaken with respect to those minerals or natural resources. One does not explore for gasoline, kerosene, or number 2 fuel oil, for example; rather, one explores for the depletable product, such as crude oil or natural gas. Once that crude oil or natural gas has been refined or processed, however, Congress intended to make clear that the “products thereof” (the gasoline, kerosene, number 2 fuel oil, etc.) could be transported and marketed and still give rise to qualifying income.

Commenters cautioned, however, that the Treasury Department and the IRS should take into account the words “of a character” in the definition of mineral or natural resource and the additional legislative history from 1988. That legislative history explained: “The reference in the bill to products for which a depletion deduction is allowed is intended only to identify the minerals or natural resources and not to identify what income from them is treated as qualifying income. Consequently, whether income is taken into account in determining percentage depletion under section 613 does not necessarily determine whether such income is qualifying income under section 7704(d).” S. Rep. No. 100–445, at 424 (1988). Commenters expressed the concern that the Treasury Department and the IRS would interpret the statutory definition to require those performing qualifying activities to have started with a depletable product themselves or otherwise be eligible to claim depletion deductions under section 611.

The Treasury Department and the IRS agree with the commenters that the definition of mineral or natural resource under section 7704(d)(1) does not require continual ownership or control of the depletable asset from extraction through each of the eight listed active terms, but that qualifying activities can take place beginning at different points along that progression of activities described by the active terms by those who purchase, take control of, or merely perform section 7704(d)(1)(E) activities with respect to partially processed or refined minerals or natural resources. Compare with §§ 1.611–1(b) and (c) and 1.613–1(a) (providing that annual depletion deductions are allowed only to the owner of an economic interest in mineral deposits or standing timber). In adding the definition of minerals or natural resources to section 7704(d)(1), Congress meant to delineate the type of asset involved, and not to require any particular type of control or ownership of the property. See H.R. Rep. No. 100–1104(II), at 16 (1988) (“the Senate amendment includes as qualifying income of publicly traded partnerships the income from any depletable property (rather than from property eligible for percentage depletion. . .)”). The definitions of the eight listed active terms in these final regulations contemplate that qualifying income may arise from certain activities that may be performed on products altered by earlier qualifying activities.

In addition to the income and gains derived from certain activities related to minerals or natural resources, Congress expanded section 7704(d)(1)(E) in 2008 to include income and gains from certain activities related to industrial source carbon dioxide, fuels described in section 6426(b) through (e), alcohol fuel defined in section 6426(b)(4)(A), or biodiesel fuel as defined in section 40A(d)(1) as qualifying income. Because the IRS has not received many PLR requests related to these products, the preamble to the proposed regulations asked whether guidance is needed with respect to those activities and, if so, the specific items the guidance should address. In response, commenters suggested that although liquefied natural gas (LNG) and liquefied petroleum gas (LPG) are included within those fuels described in section 6426(b), they should also be specifically identified as natural resources under section 7704(d)(1)(E). In the alternative, commenters requested that the final regulations treat the liquefaction and regasification of natural gas as part of transportation.

These final regulations do not list LNG and LPG as natural resources since they are not a mineral or natural resource under the definition provided by Congress. Neither LNG nor LPG is found in mines, wells, or other natural deposits listed in section 611, but each is instead a result of processing or refining petroleum or natural gas, as well as of activities to prepare the processed or refined product for storage and transportation. The Treasury Department and the IRS thus agree with commenters that liquefaction and regasification of natural gas may be part of transportation as further discussed in section III.E of this Summary of Comments and Explanation of Revisions. Therefore, these final regulations include liquefying or regasifying natural gas on the list of qualifying transportation activities. Because the Treasury Department and the IRS received no other comments seeking guidance with respect to industrial source carbon dioxide, fuels described in section 6426(b) through (e), alcohol fuel defined in section 6426(b)(4)(A), or biodiesel fuel as defined in section 40A(d)(1), these final regulations do not provide any further guidance with respect to those items.

 

The proposed regulations provided that qualifying income included only income and gains from qualifying activities, which were defined to include section 7704(d)(1)(E) activities and intrinsic activities. The proposed regulations further provided an exclusive list of operations that comprised the section 7704(d)(1)(E) activities. Although the list could be expanded by the Commissioner through notice or other forms of published guidance, the proposed regulations specifically stated that “[n]o other activities qualify as section 7704(d)(1)(E) activities.”

Numerous commenters objected to the use of an exclusive list of section 7704(d)(1)(E) activities. They argued that a static list would ignore technological advances in the dynamic mineral and natural resource industries and doubted the ability of the Treasury Department and the IRS to expeditiously issue guidance updating the list when needed. One commenter noted that an exclusive list is appropriate only when the universe of matters to be included or excluded is known, defined, considered, and categorized. The commenter questioned whether the Treasury Department and the IRS are aware of all of the current activities taking place in the mineral and natural resource industries. Illustrating these concerns, many commenters cited examples of activities they believed were omitted from the list (either through inadvertence or lack of knowledge). Rather than an exclusive list, some commenters recommended that the final regulations provide a general description of the eight listed active terms in section 7704(d)(1)(E) (that is, exploration, development, mining or production, processing, refining, transportation, and marketing), followed by a non-exclusive list of examples of qualifying activities and, where appropriate, non-qualifying activities. They suggested that such a list would provide helpful guidance to PTPs, while allowing other activities to be treated as qualifying, including through the issuance of PLRs.

Recognizing the practical difficulties of ensuring comprehensive coverage of the activities generating qualifying income, the Treasury Department and the IRS agree with commenters that the list of section 7704(d)(1)(E) activities should not be exclusive. Therefore, these final regulations provide a general definition of each of the eight listed active terms in section 7704(d)(1)(E) followed by a non-exclusive list of examples of each. The Treasury Department and the IRS anticipate that by setting forth the known activities that generate qualifying income, the guidance will be clearer and, as a result, the number of PLR requests the IRS receives will decrease. At the same time, the Treasury Department and the IRS do not intend that these final regulations be interpreted or applied in an expansive manner. Instead, they should be interpreted and applied in a manner that is consistent with their plain meaning and the overall intent of Congress to restrict this exception to treatment as a corporation under section 7704(a) as described in section I of this Summary of Comments and Explanation of Revisions.

The proposed regulations defined exploration as an activity performed to ascertain the existence, location, extent, or quality of any deposit of mineral or natural resource before the beginning of the development stage of the natural deposit by: (1) drilling an exploratory or stratigraphic type test well; (2) conducting drill stem and production flow tests to verify commerciality of the deposit; (3) conducting geological or geophysical surveys; or (4) interpreting data obtained from geological or geophysical surveys. For minerals, exploration also included testpitting, trenching, drilling, driving of exploration tunnels and adits, and similar types of activities described in Rev. Rul. 70–287 (1970–1 CB 146), if conducted prior to development activities with respect to the minerals.

Separately, the proposed regulations defined development as an activity performed to make minerals or natural resources accessible by: (1) drilling wells to access deposits of minerals or natural resources; (2) constructing and installing drilling, production, or dual purpose platforms in marine locations, or any similar supporting structures necessary for extraordinary non-marine terrain (such as swamps or tundra); (3) completing wells, including by installing lease and well equipment, such as pumps, flow lines, separators, and storage tanks, so that wells are capable of producing oil and gas and the production can be removed from the premises; (4) performing a development technique such as, for minerals, stripping, benching and terracing, dredging by dragline, stoping, and caving or room-and-pillar excavation, and for oil and natural gas, fracturing; or (5) constructing and installing gathering systems and custody transfer stations.

One commenter noted that the proposed regulations provided a workable definition of exploration and development activities consistent with past standards of industry practice, but did not allow for changes in technologies developed in the future. Another commenter recommended expanding the list to include any activity the payment for which is: (1) a geological or geophysical cost under section 167(h); (2) an intangible drilling cost under section 263(c); or (3) a mine exploration or development cost under section 616(a) or 617(a). According to the commenter, the benefit of such a rule is that the relevant industries understand the costs covered by those Code provisions and the law in the area is well developed.

The only change made to the definitions of exploration and development in these final regulations is the addition of the word “including” to show that the list of activities is not exclusive, as discussed in section III.A of this Summary of Comments and Explanation of Revisions. These final regulations do not adopt the suggestion to include as a qualifying activity all services giving rise to costs under section 167(h), 263(c), 616(a), or 617(a). Some of the activities are already specifically included in the definitions of section 7704(d)(1)(E) activities, but others would expand the list of qualifying activities beyond that intended by Congress and allow service-provider PTPs to circumvent the intrinsic test in § 1.7704–4(d). As discussed in section I of this Summary of Comments and Explanation of Revisions, Congress enacted section 7704 to restrict the growth of PTPs due to “concern about long-term erosion of the corporate tax base.” H.R. Rep. No. 100–391, at 1065 (1987). Congress made an exception for natural resource activities in part because it recognized the fragile economic conditions in those industries at the time. Id. at 1066. Although Congress intended to benefit oil and gas developers, it did not intend to exempt, for example, construction and debris removal companies, suppliers, or other non-specialized service providers to those industries. Intangible drilling costs, for example, include amounts paid for fuel, repairs, hauling, and supplies. See §§ 1.263(c)–1 and 1.612–4(a). Although these costs may be necessarily incurred by oil and gas developers, that does not mean that a third-party service provider that receives payment for those services is performing activities giving rise to qualifying income.

The proposed regulations defined mining or production as an activity performed to extract minerals or other natural resources from the ground by: (1) operating equipment to extract natural resources from mines and wells; or (2) operating equipment to convert raw mined products or raw well effluent to substances that can be readily transported or stored (for example, passing crude oil through mechanical separators to remove gas, placing crude oil in settling tanks to recover basic sediment and water, dehydrating crude oil, and operating heater-treaters that separate raw oil well effluent into crude oil, natural gas, and salt water).

Generally, commenters sought to expand the definition of mining or production. They suggested that the regulations adopt the definition of mining from section 613, which includes not only the extraction of ores or minerals from the ground but also certain mining processes. See section 613(c)(2). Similarly, commenters suggested that the regulations define production to include not only the extraction of oil or natural gas from the well but also certain processing activities that occur post-production up to the “depletion cut-off point” established under sections 611 and 613. These commenters explained that the explicit reference in section 7704(d)(1) to the depletion rules in section 611 should be interpreted as meaning that all the terms in 7704(d)(1)(E) should be defined the same as the terms in section 611. A consequence of expanding the definition of mining or production to include certain processing activities, commenters reasoned, is that the definition of processing for purposes of section 7704(d)(1)(E) would necessarily encompass something more, further expanding qualifying activities as discussed in section III.D.3 of this Summary of Comments and Explanation of Revisions (concerning processing and refining of ores and minerals other than crude oil and natural gas). Finally, one commenter noted that, in addition to mining from the ground, minerals and natural resources can be extracted from waste deposits or residue from prior mining, and that such extraction should also be treated as mining or production. See section 613(c)(3) and § 1.613–4(i).

These final regulations do not adopt the suggestion to expand the definition of mining or production to include mining processes or other processing activities before the depletion cut-off point. Instead, these final regulations clarify the proposed regulations’ definition of mining or production activities to include only extraction activities. In addition, the final regulations move activities that convert raw mined products or raw well effluent into products that can be readily transported or stored to the definition of processing. As a result, qualifying processing activities are included under the definition of processing in these final regulations. In its entirety, section 7704(d)(1)(E) covers a broader category of income than and contemplates a different end point of activities from those of sections 611 and 613, and therefore the definitions of mining and production are not interchangeable between the two regimes. Sections 611 and 613 describe what is gross income from the exhaustion of capital assets for purposes of applying the depletion rules. See section 611(a) and United States v. Cannelton Sewer Pipe Co., 364 U.S. 76, 81–85 (1960). For purposes of section 613, mining, an upstream activity, generally includes those treatments normally applied to prepare an extracted mineral or natural resource to the point at which it is first marketable (which may involve a limited amount of processing and transportation), but no further. See section 613(c)(2). In contrast, section 7704(d)(1)(E) separately lists certain upstream, midstream, and downstream activities, encompassing a progression of stages of activities performed upon a mineral or natural resource up to the point at which products are typically produced at field facilities and petroleum refineries or the equivalent for other natural resources, as well as transportation and marketing thereafter. It would therefore be duplicative to define mining to include both mining and mining processes as defined in section 613 for purposes of section 7704(d)(1)(E). The reference in section 7704(d)(1) to section 611 merely defines the scope of included minerals and natural resources as discussed in section II of this Summary of Comments and Explanation of Revisions. Nothing in the statute indicates that other concepts in section 611 and 613 are intended to be incorporated as well.

These final regulations adopt the request that mining or production be defined to include the extraction of minerals or natural resources from the waste deposits or residue of prior mining or production. The recycling of scrap or salvaged metals or minerals from previously manufactured products or manufacturing processes, however, is not considered to be the extraction of ores or minerals from waste or residue, and therefore does not give rise to qualifying income.

The proposed regulations combined the activities of processing and refining together in one definition that included both a general definition followed by specific rules for different categories of natural resources (natural gas, petroleum, ores and minerals, and timber). The vast majority of the comments received on the proposed regulations concerned the definition of processing or refining, addressing issues related to both the general definition and specific rules. Section III.D.1 of this Summary of Comments and Explanation of Revisions addresses the comments related to the general definition. Sections III.D.2 through III.D.4 of this Summary of Comments and Explanation of Revisions address comments related to the specific rules.

The general definition of processing and refining in the proposed regulations stated that, except as otherwise provided, an activity was processing or refining if done to purify, separate, or eliminate impurities, but would not qualify if: (1) the PTP did not use a consistent Modified Accelerated Cost Recovery System (MACRS) class life for assets used in the activity (the MACRS consistency requirement); (2) the activity caused a substantial physical or chemical change in a mineral or natural resource (the physical and chemical change limitation); or (3) the activity transformed the extracted mineral or natural resource into a new or different mineral product or into a manufactured product (the manufacturing limitation).

Multiple commenters argued that the proposed regulations’ use of a joint definition for processing and refining wrongly read the term “processing” out of the statute. These commenters reasoned that Congress used a comma between the terms to indicate that each term must be accorded significance and effect, in contrast to the “or” between mining (for ores and minerals) or production (for natural gas and crude oil), which described the same activity but with respect to different industries. Commenters noted that the version of the legislation that passed in the House did not include the term processing. Rather, it was added in conference and therefore must mean that the two terms are not synonymous. While some commenters admitted that it is not uncommon in the industry to use the words processing and refining interchangeably to refer to the same activities, they maintained that Congress intended to include a broader range of activities than either word alone would allow.

Although the Treasury Department and the IRS have determined that the terms can overlap, these final regulations adopt the suggestion of defining processing and refining separately in order to better clarify what activities generate qualifying income under section 7704(d)(1)(E). These final regulations generally define processing for purposes of section 7704(d)(1)(E) as an activity performed to convert raw mined or harvested products or raw well effluent to substances that can be readily transported or stored as further described in the specific rules for the different categories of natural resources. This definition captures the processing that is generally performed at the wellhead, mine, field facilities, or other location where mining processes are generally applied, as described in § 1.613–4(f)(1)(iii), because the legislative history contemplates that qualifying activities do not include activities that create products through additional processing beyond that of petroleum refineries or field facilities.

These final regulations do not provide a general definition of refining, but instead set forth the activities that qualify as refining activities under the specific rules for the different categories of natural resources. Consistent with the discussion in section III.D.1.e of this Summary of Comments and Explanation of Revisions, the Treasury Department and the IRS have concluded that refining does not have general application to all minerals and natural resources.

Commenters argued that the requirement in the proposed regulations that a PTP use a consistent MACRS class life for assets generating qualifying income as a result of being used for processing or refining has no statutory support and would create uncertainty for PTPs and their investors. They stressed that it would be inappropriate to deny qualifying income treatment to a PTP whose activities met the definition of processing or refining merely because it, or a processor or refiner further upstream, failed to use the appropriate MACRS class life. Commenters also challenged the idea that the asset class lives in Rev. Proc. 87–56 (1987–2 CB 674) are helpful in distinguishing between qualifying and non-qualifying activities. Commenters raised similar concerns regarding the discussion of the North American Industry Classification System (NAICS) codes in the preamble of the proposed regulations to give examples of qualifying activities.

The proposed regulations included a MACRS requirement because the Treasury Department and the IRS believed MACRS provided a useful demarcation of those processing and refining activities typically performed by a field facility or a refinery, as compared to non-qualifying processing activities performed further downstream from those activities, such as petrochemical manufacturing or the manufacturing of pulp and paper. Compare, for example, Rev. Proc. 87–56, asset class 13.3 (Petroleum Refining) and asset class 28.0 (Manufacture of Chemicals); also, asset class 24.1 (Cutting of Timber) and asset class 26.1 (Manufacture of Pulp and Paper). In addition, the IRS released Rev. Proc. 87–56 six months before the passage of section 7704, making that demarcation contemporaneous with section 7704. After consideration of the comments received on this issue, however, the Treasury Department and the IRS are persuaded that the MACRS class lives are not comprehensive nor sufficiently detailed for every industry. Accordingly, these final regulations do not include a MACRS consistency requirement. Nor do these final regulations reference the NAICS codes. Notwithstanding the lack of a MACRS consistency requirement, MACRS or NAICS codes nevertheless may provide useful insight when determining whether an activity generates qualifying income as provided in these final regulations.

Many commenters contended that the physical and chemical change limitation in the proposed regulations ignored decades-old authorities that such transformative changes are an understood and realistic part of processing and refining. See § 1.613A–7(s) (refining crude oil is “any operation by which the physical or chemical characteristics of crude oil are changed”); IRM § 4.41.1.6.1 (modern refining operations may involve the “separation of components plus the breaking down, restructuring, and recombining of hydrocarbon molecules”); Processing, New Oxford American Dictionary, 1307 (2001 ed.) (to perform a series of mechanical or chemical operations on, in order to change or preserve it). Commenters also criticized the reference to § 1.613–4(g)(5) in the preamble of the proposed regulations, cited to show that the physical and chemical change limitation was consistent with definitions found elsewhere in the Code and regulations. They argued that the physical and chemical change prohibition in § 1.613–4(g)(5) is helpful only in determining what is not included in calculating gross income from the exhaustion of capital assets for purposes of applying the depletion rules, but not in distinguishing when an activity qualifies as processing or refining under section 7704(d)(1)(E).

The Treasury Department and the IRS agree with the commenters that processing and refining may cause a substantial physical or chemical change, depending on the mineral or natural resource at issue. Indeed, the specific rule in the proposed regulations for the processing or refining of petroleum recognized that refineries perform physical and chemical changes, for example when converting the physically separated components of crude oil into gasoline or other fuels. Accordingly, because the general definition is at odds with some of the specific rules for certain natural resources, these final regulations no longer include a general physical or chemical change limitation.

Commenters criticized the manufacturing limitation in the proposed regulations, arguing that the activities that qualify as processing and refining under section 7704(d)(1)(E) are types of manufacturing. Many commenters elaborated that the proposed regulations wrongly focus on the output of an activity. These commenters maintained that the entire analysis should instead rest on whether or not the input is a mineral or natural resource, or a product thereof. That is, so long as an item was once a mineral or natural resource, the income derived from any further processing or refining of the item up to and, some argued, including a plastic is qualifying. Similar to the comments regarding the definition of mineral or natural resource discussed in section II of this Summary of Comments and Explanation of Revisions, these comments reflect a belief that the Treasury Department and the IRS have misinterpreted the statement in the legislative history that “[o]il, gas, or products thereof are not intended to encompass oil or gas products that are produced by additional processing beyond that of petroleum refineries or field facilities,” H.R. Rep. No. 100–495, at 947 (1987), as a limitation on processing and refining instead of a clarification of what is included as a natural resource that can be further processed and refined. As a corollary to the comments regarding output, some commenters argued that Congress knew how to, but did not, limit processing and refining to the creation of certain products, for example by specifying “or any primary products thereof” as it did when listing oil and gas as excluded property under the Foreign Sales Corporation provisions enacted in 1984. See section 927(a)(2)(C), now repealed.

As discussed in section I of this Summary of Comments and Explanation of Revisions, the Treasury Department and the IRS interpret the terms processing and refining in section 7704(d)(1)(E) and the legislative history as capturing those activities that produce the products typically found at field facilities and petroleum refineries, or the equivalent for other natural resources. The Treasury Department and the IRS do not construe the lack of the word “primary” in the legislative history as an indication that products produced through additional processing beyond the refinery or field facility should be included. Instead, the similarity between the list of products in the regulations under former section 927 and in the legislative history for section 7704(d)(1)(E) indicate that Congress understood processing and refining oil and natural gas to result in the products identified as primary products in the regulations under former section 927. Compare § 1.927(a)–1T(g)(2)(i) (defining “primary product from oil” as crude oil and all products derived from the destructive distillation of crude oil, including volatile products, light oils such as motor fuel and kerosene, distillates such as naphtha, lubricating oils, greases and waxes, and residues such as fuel oil) and § 1.927(a)–1T(g)(2)(ii) (defining “primary product from gas” as all gas and associated hydrocarbon components from gas or oil wells, whether recovered at the lease or upon further processing, including natural gas, condensates, liquefied petroleum gases such as ethane, propane, and butane, and liquid products such as natural gasoline) with the Conference Committee Report for section 7704(d)(1)(E), H.R. Rep. No. 100–495, at 947 (1987) (“gasoline, kerosene, number 2 fuel oil, refined lubricating oils, diesel fuel, methane, butane, propane”).

The Treasury Department and the IRS recognize, however, that the wording of the manufacturing limitation in the proposed regulations was vague and could cause confusion. Therefore, the general definitions of processing and refining in the final regulations no longer contain the specific language that made up the manufacturing limitation. Instead, the specific definitions for the processing and refining of natural gas and crude oil capture congressional intent by including only those activities that are generally performed at field facilities and petroleum refineries, or those that produce products typically found at field facilities and refineries. The definitions for processing and refining do not include additional processing or manufacturing activities, such as petrochemical manufacturing. The final regulations apply a similar end point for the processing and refining of ores, other minerals, and timber in a manner tailored to the type of resource at issue.

Some commenters dismissed the need for industry specific rules. These commenters maintained that Congress did not limit qualifying income based on the different processes used for the various types of minerals and natural resources, and therefore one overarching definition should apply consistently across all resources.

The final regulations retain separate definitions for processing and refining of natural gas, crude oil, ores and other minerals, and timber. As a practical matter, the minerals and natural resources subject to depletion under section 611 are different, and there is no uniform way to address them. For example, geothermal energy is not processed or refined. The processing of timber necessarily differs from the processing of natural gas. The absence of specific rules for each type of natural resource would result in vague guidelines lacking clear distinctions between qualifying and non-qualifying activities. Furthermore, a more general approach would lead to an unwarranted expansion of the scope of qualifying income beyond that intended by Congress, since a general definition would need to encompass the activities of the resource with the broadest definition of processing and refining.

The proposed regulations defined processing or refining of natural gas as an activity performed to: (1) purify natural gas, including by removal of oil or condensate, water, or non-hydrocarbon gases (including carbon dioxide, hydrogen sulfide, nitrogen, and helium); (2) separate natural gas into its constituents which are normally recovered in a gaseous phase (methane and ethane) and those which are normally recovered in a liquid phase (propane, butane, pentane, and gas condensate); or (3) convert methane in one integrated conversion into liquid fuels that are otherwise produced from petroleum. The proposed regulations defined processing or refining of petroleum as an activity, the end product of which is not a plastic or similar petroleum derivative, performed to: (1) physically separate crude oil into its component parts, including, but not limited to, naphtha, gasoline, kerosene, fuel oil, lubricating base oils, waxes and similar products; (2) chemically convert the physically separated components if one or more of the products of the conversion are recombined with other physically separated components of crude oil in a manner that is necessary to the cost-effective production of gasoline or other fuels (for example, gas oil converted to naphtha through a cracking process that is hydrotreated and combined into gasoline); or (3) physically separate products created in (1) and (2). The proposed regulations also provided a partial list of products that would not be treated as obtained through the qualified processing or refining of petroleum, including: (1) heat, steam, or electricity produced by the refining processes; (2) products that are obtained from third parties or produced onsite for use in the refinery, such as hydrogen, if excess amounts are sold; and (3) any product that results from further chemical change of the product produced from the separation of crude oil if it is not combined with other products separated from the crude oil. For example, the proposed regulations indicated that production of petroleum coke from heavy (refinery) residuum qualifies as processing or refining, but any upgrading of petroleum coke (such as to anode-grade coke) does not qualify because it is further chemically changed.

Numerous commenters argued that the proposed regulations inappropriately favored (1) crude oil over natural gas, and (2) fuel products over other products. For example, under the proposed regulations, qualifying processing or refining included chemically converting the component parts of crude oil into products that would be combined into a fuel and products that could be separated further, sometimes resulting in olefins such as ethylene and propylene. In contrast, the proposed regulations recognized as qualifying only the conversion of one component of natural gas (methane) into a fuel, and did not treat as qualifying the creation of olefins from natural gas. Commenters asserted that there is no basis for differentiating between hydrocarbon sources for fuels or olefins, and that such differentiation causes difficulties for pipeline operators and marketers, who cannot tell if the fungible fuels or olefins come from qualifying crude oil processing or non-qualifying natural gas conversions. Also regarding this same language in the proposed regulations, one commenter asked that the phrase “in one integrated conversion” be clarified so as to not exclude multistep conversion techniques which result in gasoline. Similarly, commenters contended that the refining of lubricants, waxes, solvents, and asphalts should also be included as qualifying activities since they, like fuel, are products of petroleum refineries.

Two commenters stated that the proposed regulations were not consistent in favoring fuels since the sale of methanol was not treated as a qualifying activity. See proposed § 1.7704–4(e), Example 3 (concluding that “the production and sale of methanol, an intermediate product in the conversion [from methane to diesel], is not a section 7704(d)(1)(E) activity because methanol is not a liquid fuel otherwise produced from the processing of crude oil”). These commenters argued that the processing and sale of methanol should be a qualifying activity because it: (1) is similar to methane or to natural gas liquids (NGLs), (2) is an intermediate product produced in the act of converting gas into gasoline, (3) is itself a fuel (albeit an alcohol fuel), and (4) can be produced from oil using typical refinery processes, catalysts, and equipment.

Rather than the definitions in the proposed regulations, commenters offered two different possible regulatory standards for determining whether an activity qualifies as the processing or refining of crude oil or natural gas: (1) whether the activity is performed in a crude oil refinery; or (2) whether the activity produces a product of a type that is produced in a crude oil refinery. For the second recommended standard, some commenters suggested that the final regulations adopt the list of products produced by a refinery as compiled by the U.S. Energy Information Administration (EIA). In support of this second standard, one commenter said that using the EIA list would give effect to the congressional intent that oil and gas products necessitating processing beyond the type of processing that takes place in petroleum refineries should not give rise to qualifying income. Another commenter added that using the second standard would make the regulations administrable by avoiding inquiry into the nature and extent of the production process. Other commenters recommended that the final regulations provide a list of “bad products,” that is products of processing or refining that do not give rise to qualifying income, such as a list of plastic resins maintained by trade industry associations for the plastic industry.

In response to these comments, these final regulations make several changes. First, as discussed in section III.D.1.a of this Summary of Comments and Explanation of Revisions, these final regulations separately define processing and refining. Processing of natural gas and crude oil for purposes of section 7704(d)(1)(E) encompasses those activities that convert raw well effluent to substances that can be readily transported or stored, that is, what is generally performed at the wellhead or field facilities. For natural gas, processing is the purification of natural gas, including by removing oil or condensate, water, or non-hydrocarbon gases (such as carbon dioxide, hydrogen sulfide, nitrogen, and helium), and the separation of natural gas into its constituents which are normally recovered in a gaseous phase (methane and ethane) and those which are normally recovered in a liquid phase (propane, butane, pentane, and gas condensate). For crude oil, processing is the separation of crude oil by passing it through mechanical separators to remove gas, placing crude oil in settling tanks to recover basic sediment and water, dehydrating crude oil, and operating heater-treaters that separate raw oil well effluent into crude oil, natural gas, and salt water.

Second, consistent with the legislative history’s limitation to products of petroleum refineries or field facilities, the Treasury Department and the IRS adopt the suggestion to list the qualifying products of a refinery for the definition of refining of natural gas and crude oil for purposes of 7704(d)(1)(E) and, for this purpose, look to information compiled by the EIA. The Treasury Department and the IRS have determined that the EIA currently provides an authoritative list of products of a refinery. Following the oil market disruption in 1973, Congress established the EIA in 1977 to collect, analyze, and disseminate comprehensive, independent and impartial energy information in order to assess the adequacy of energy resources to meet economic and social demands. See 42 U.S.C. 7135(a). As part of that mandate, the EIA is required to gather information from persons engaged in ownership, control, exploration, development, extraction, refining or otherwise processing, storage, transportation, or distribution of mineral fuel resources. See 42 U.S.C. 7135(h)(4) and (6). These final regulations are informed by Form EIA–810, “Monthly Refinery Report,” and Form EIA–816, “Monthly Natural Gas Liquids Report,” which are the surveys that each refinery or natural gas processing plant must complete to report both finished and unfinished products of their operations.

Specifically, these final regulations define the refining of natural gas and crude oil as the further physical or chemical conversion or separation processes of products resulting from processing and refining activities, and the blending of petroleum hydrocarbons, to the extent they give rise to products listed in the definition of processing or the following products: ethane, ethylene, propane, propylene, normal butane, butylene, isobutane, isobutene, isobutylene, pentanes plus, unfinished naphtha, unfinished kerosene and light gas oils, unfinished heavy gas oils, unfinished residuum, reformulated gasoline with fuel ethanol, reformulated other motor gasoline, conventional gasoline with fuel ethanol – Ed55 and lower gasoline, conventional gasoline with fuel ethanol – greater than Ed55 gasoline, conventional gasoline with fuel ethanol – other conventional finished gasoline, reformulated blendstock for oxygenate (RBOB), conventional blendstock for oxygenate (CBOB), gasoline treated as blendstock (GTAB), other motor gasoline blending components defined as gasoline blendstocks as provided in § 48.4081–1(c)(3), finished aviation gasoline and blending components, special naphthas (solvents), kerosene-type jet fuel, kerosene, distillate fuel oil (heating oils, diesel fuel, ultra-low sulfur diesel fuel), residual fuel oil, lubricants (lubricating base oils), asphalt and road oil (atmospheric or vacuum tower bottom), waxes, petroleum coke, still gas, and naphtha less than 401°F end-point, as well as any other products of a refinery that the Commissioner may identify through published guidance.

The final regulations have modified or clarified several of the terms from the EIA lists to ensure that the listed products are only those of the type produced in a petroleum refinery or traditional gas field processing plant. Thus, for example, the listed product “lubricants” includes the parenthetical “lubricating base oils” to clarify that refining does not include creating a lubricant not of the type produced in a petroleum refinery that has been mixed with non-petroleum hydrocarbons. The EIA reports are required to be filed only by refiners and natural gas processors; consequently, the EIA need not circumscribe the products to include solely those generally produced by a petroleum refinery or processing plant. The Treasury Department and the IRS modified the EIA list to more specifically identify those products solely produced by refineries and field facilities. In addition, the list in the final regulations must be read consistently with that view to include only those types of listed products that are generally produced in a petroleum refinery or natural gas processing plant. For example, a lubricant that is not of a type that is generally produced by a refiner is not within the product list. Therefore, the definitions have been slightly adjusted to reflect lubricants of a petroleum refinery as opposed to those from a manufacturer or entity that is adding more than the minimal amount permitted under additization (discussed in section III.H.5 of this Summary of Comments and Explanation of Revisions) of different minerals, natural resources, or other products to the lubricant.

Also, in adopting the approach of listing the products of a petroleum refinery or a natural gas processing plant, these final regulations no longer provide language regarding converting methane in one integrated conversion into liquid fuels or regarding the various acceptable chemical conversions with respect to crude oil. Activities are treated as refining to the extent they give rise to products listed in the regulation.

Adopting the EIA’s list of products of a refinery resolved several other issues raised by commenters. These final regulations no longer differentiate between the refining of natural gas and the refining of crude oil, particularly in regard to the creation of olefins and certain liquid fuels. Although traditional gas field processing plants do not produce olefins or certain fuels from natural gas, these products are created in petroleum refineries (albeit in small quantities in the case of olefins). The Treasury Department and the IRS recognize that changes in technology have expanded the ways to create liquid fuels, and thus continue to be guided by the stated goal in the legislative history of including as qualifying those activities that create products “which are recovered from petroleum refineries or field facilities.” H.R. Rep. No. 100–495, at 947 (1987). Similarly, the final regulations no longer omit the refining of non-fuel products of a refinery, such as lubricants, waxes, solvents, and asphalts of the type produced in petroleum refineries.

Conversely, the EIA list does not include methanol as a product of a refinery or natural gas processing plant, and therefore these final regulations do not adopt commenters’ suggestion to treat as qualifying the creation of methanol. Indeed, one commenter who recommended adopting the list of products produced by a refinery as compiled by the EIA acknowledged that the Treasury Department and the IRS would need to expand the EIA list to encompass methanol and synthesis gas since they are typically not produced at refineries. Given the EIA’s expertise, the Treasury Department and the IRS decline to supplement the products of a refinery as identified by the EIA, and also note that alcohols (such as methanol) were specifically not included as a primary product of oil and gas in the regulations under the Foreign Sales Corporation provisions, whose list of oil and gas products is similar to that in the legislative history for section 7704(d)(1)(E). See § 1.927(a)–1T(g)(2)(iv) and discussion under section III.D.1.d of this Summary of Comments and Explanation of Revisions. Whether methanol is similar to NGLs, is a liquid fuel, or can be created using typical oil refining processes is immaterial to the determination of whether the manufacture of methanol is a qualifying activity. These final regulations, therefore, amend the reasoning in Example 3, now in § 1.7704–4(f), to reflect that methanol is not included among the listed products.

These final regulations also do not adopt the recommendation to treat as qualifying all activities performed in a refinery. Such a standard would allow PTPs to thwart Congress’s limitation on qualifying activities by simply moving processes that are normally not conducted in a refinery within the refinery fence. For example, some refineries have added hydrogen production plants to their facilities, though Congress did not intend the generation of hydrogen for sale to be a qualifying activity. Indeed, these final regulations continue to provide that products of refining do not include products produced onsite for the use in the refinery, such as hydrogen, if excess amounts are sold. The Treasury Department and the IRS understand that some commenters suggested this broader definition of refining in order to include as qualifying the refining of non-fuel products (lubricants, waxes, solvents, and asphalts). Their concern, however, is addressed to the extent those products are included in the list of products of a refinery, thus avoiding the need for a broad and potentially vague rule that would encompass all activities undertaken in a refinery.

Finally, these final regulations retain language similar to that in the proposed regulations clarifying that certain other products are not products of refining, including heat, steam or electricity produced by refining processes, products obtained from third parties or produced onsite for use in the refinery if excess amounts are sold, any product that results from further chemical change of a product on the list of products of a refinery that does not result in the same or another product listed as a product of a refinery, and plastics or similar petroleum derivatives. For this last item, these final regulations do not adopt the suggestion of some commenters to provide a non-exclusive list of non-qualifying plastic resins, as the Treasury Department and the IRS do not agree that providing such a list aids taxpayers. A list of some of the non-qualifying products is not relevant because the final regulations list all of the qualifying products and might create confusion if a product were not included on either list.

The proposed regulations provided that an activity constituted processing or refining of ores and minerals if it met the definition of mining processes under § 1.613–4(f)(1)(ii) or refining under § 1.613–4(g)(6)(iii). In addition, the proposed regulations repeated part of the definition of refining found in § 1.613–4(g)(6)(iii) by stating that, generally, refining of ores and minerals is any activity that eliminates impurities or foreign matter from smelted or partially processed metallic and nonmetallic ores and minerals, as for example the refining of blister copper.

Commenters generally sought to expand the definition of processing and refining of ores and minerals. As discussed in greater detail in section III.C of this Summary of Comments and Explanation of Revisions, commenters maintained that section 7704(d)(1)(E) should use the definition of mining from section 613(c)(2). Because that definition already includes certain mining processes, commenters further argued that the definition of processing for section 7704(d)(1)(E) should include something more, specifically some or all of the “nonmining processes” listed in section 613(c)(5) and § 1.613–4(g). Moreover, they reasoned that unless the nonmining processes are included in the definition of processing, there is a hole between processing and refining, as defined in the proposed regulations, which could not have been intended. For example, the proposed regulations identified the refining of blister copper as a qualifying activity, but did not allow as qualifying the activity that precedes that step (that is, the smelting of the copper ore concentrate to produce the blister copper), which occurs after the mining processes identified in § 1.613–4(f)(2)(i)(d). Additionally, commenters elaborated that some of the nonmining processes under section 613(c)(5) are themselves activities that “purify, separate, or eliminate impurities,” thus falling within the general definition of processing provided in the proposed regulations. Some commenters argued that the coking of coal, the making of activated carbon, and the fine pulverization of magnetite should all be considered qualifying activities.

Based on the comments received, the Treasury Department and the IRS have determined that the definition of processing and refining of ores and minerals in the proposed regulations needed clarification. Like the final regulations on processing and refining of natural gas or crude oil, and as discussed in section III.D.1.a of this Summary of Comments and Explanation of Revisions, these final regulations separately define processing and refining of ores and minerals other than natural gas or crude oil.

Processing of ores and minerals other than natural gas or crude oil is defined in these final regulations as those activities that meet the definition of mining processes under § 1.613–4(f)(1)(ii), without regard to § 1.613–4(f)(2)(iv) (related to who is performing the processing). Accordingly, processing includes the activities generally performed at or near the point of extraction of the ores or minerals from the ground (generally within a 50-mile radius or greater if the Commissioner determines that physical or other requirements cause the plants or mills to be at a greater distance) that are normally applied to obtain commercially marketable mineral products. Therefore, this definition captures the concept of “field facilities” in the legislative history to section 7704(d)(1)(E).

Because the legislative history does not provide any examples of products produced from ores and minerals that may generate qualifying income, other than those relating to oil, gas, and fertilizer, the Treasury Department and the IRS have applied limitations to ores and minerals that are comparable to those specifically expressed by Congress regarding oil and gas. See H.R. Rep. No. 100–495, at 947 (1987) (“[o]il, gas, or products thereof are not intended to encompass oil or gas products that are produced by additional processing beyond that of petroleum refineries or field facilities, such as plastics or similar petroleum derivatives”). In contrast, commenters’ suggestion to include nonmining processes in the definition of processing is not consistent with the Treasury Department’s and the IRS’s view of congressional intent because the term “nonmining processes” in § 1.613–4(g) is a catch-all category that includes any process applied beyond mining processes, including refining, blending, manufacturing, transportation, and storage. See § 1.613–4(g) (which lists various nonmining processes, and also provides that “a process applied subsequent to a nonmining process (other than nonmining transportation) shall also be considered to be a nonmining process”). In addition to causing the definition of processing to be partly duplicative of other listed section 7704(d)(1)(E) activities, adopting this suggestion would mean that so long as a product started as a depletable product, any income derived from any manipulation of that product would be qualifying income. Such a result would be in direct conflict with the desire of Congress to restrict the scope of activities engaged in by PTPs. Therefore, these final regulations do not adopt that suggestion.

Nevertheless, in response to comments, these final regulations include some nonmining processes in the definition of refining of ores and minerals other than natural gas or crude oil. Refining of ores and minerals other than natural gas or crude oil is defined in these final regulations as those various processes subsequent to mining processes performed to eliminate impurities or foreign matter and which are necessary steps in the goal of achieving a high degree of purity from specified metallic ores and minerals which are not customarily sold in the form of the crude mineral product. The specified metallic ores and minerals identified in these final regulations are: lead, zinc, copper, gold, silver, and any other ores or minerals that the Commissioner may identify through published guidance. These are the same metallic ores and minerals treated as “not customarily sold in the form of the crude mineral product” under section 613(c)(4)(D), except that fluorspar ores and potash are not included in these regulations because they will be addressed in regulations specifically addressing fertilizer and uranium is not included because it is not purified to a high concentrate. Uranium is not mined to isolate pure uranium at the high-purity levels as is done with other metals such as lead, zinc, copper, gold, or silver, but, overwhelmingly, is instead mined to attain a uranium oxide (UO2) material for the manufacture of nuclear fuel pellets. This process rejects approximately 95–99 percent of the originally-extracted uranium ore (a U238 + U235 mixture), in order to raise the concentration of the desired uranium isotope (U235), in what the Treasury Department and the IRS have concluded is a manufacturing process.

Refining processes for these specified metallic ores and minerals include some non-mining processes (such as fine pulverization, electrowinning, electrolytic deposition, roasting, thermal or electric smelting, or substantially equivalent processes or combinations of processes) to the extent those processes are used to separate or extract the metal from the specified metallic ore for the primary purpose of producing a purer form of the metal, as for example the smelting of concentrates to produce Doré bars or refining of blister copper. Income from the smelting of iron, for example, is not qualifying income under the final regulations because iron is an ore or mineral customarily sold in the form of the crude mineral product, and thus not a product listed in section 613(c)(4)(D). Compare § 1.613–4(f)(2)(i)(c) and (d). In addition, these final regulations specifically provide that refining does not include the introduction of additives that remain in the metal, for example, in the manufacture of alloys of gold. Also, the application of nonmining processes as defined in § 1.613–4(g) to produce a specified metal that is considered a waste or by-product during the production of a non-specified metallic ore or mineral is not considered refining.

These final regulations provide a more detailed definition of refining than the proposed regulations and better articulate a common understanding of what refining includes, that is in a metallurgical sense. To eliminate uncertainty, these final regulations define refining to include only activities with respect to those ores and minerals that are generally refined to a high degree of purity, which are also those ores and minerals that normally require more processing before they are sold, as identified in § 613(c)(4) and § 1.613–4(f)(2)(i)(d). In addition, these final regulations also allow the necessary, preceding processes performed to eliminate impurities from the specified ores and minerals, thereby addressing commenters’ concerns regarding a hole in processing activities in the proposed regulations. In providing this definition, the final regulations also effect congressional intent to limit qualifying income to certain activities that have “commonly or typically been conducted in partnership form.” H.R. Rep. No. 100–391, at 1066 (1987). Both in 1987 and since, large manufacturing operations such as smelting aluminum and manufacturing steel have generally been conducted by corporations. Despite the existence of hundreds of different ores and minerals, only a handful of businesses that work with ores and minerals other than natural gas or crude oil have operated as PTPs, perhaps reflecting a general understanding that expanded processing activities were not considered by Congress to be activities that could generate qualifying income. The Treasury Department and the IRS have determined that it would be inappropriate to expand the definition of refining of ores and minerals beyond that intended by Congress.

The final regulations do not recognize as qualifying activities the coking of coal or the making of activated carbon. The processing of coal, as contemplated by § 1.613–4(f)(2)(i)(a), includes the cleaning, breaking, sizing, dust allaying, treating to prevent freezing, and loading for shipment. At that point, the coal is ready for sale. Because Congress intended products resulting from processing to include only those products produced in field facilities or refineries, coking of coal is not a processing activity. Furthermore, coal is not refined into coke or activated carbon in the metallurgical sense in which ores are refined. Coal is itself the mineral or natural resource for purposes of sections 611 and 613 that is extracted from the ground. Unlike ores where extraction occurs in order to obtain the mineral at issue—for which refining may be required to separate the mineral from the ore rock—coal is extracted to be used substantially as is. Refining ores to obtain a purer form of the minerals found in rock is not analogous to coking coal to obtain carbon. Cokemaking and creating activated carbon are manufacturing processes used to create a new product. Refining is not changing a mineral into a new or different mineral product or creating a product that is, altogether, not a mineral.

Similarly, these final regulations do not include the fine pulverization of magnetite, as requested by a commenter. As discussed, Congress intended processing to include only those activities typically performed at the equivalent of field facilities for minerals and ores. Fine pulverization is generally not included as a mining process as it is not helpful in bringing the ores or minerals to shipping grade generally, although pulverization may qualify as a mining process if, with respect to the mineral or ore at issue, it is necessary to another process that is a mining process. See § 1.613–4(f)(2)(iii). These final regulations do not alter this treatment.

The proposed regulations provided that an activity constituted processing of timber if performed to modify the physical form of timber, including by the application of heat or pressure to timber, without adding any foreign substances. The proposed regulations specified that processing of timber did not include activities that added chemicals or other foreign substances to timber to manipulate its physical or chemical properties, such as using a digester to produce pulp. Products that resulted from timber processing included wood chips, sawdust, rough lumber, kiln-dried lumber, veneers, wood pellets, wood bark, and rough poles. Products that were not the result of timber processing included pulp, paper, paper products, treated lumber, oriented strand board/plywood, and treated poles.

Commenters argued that the proposed regulations wrongly limited the products of timber processing and restricted additives. These commenters noted that the proposed regulations departed from PLRs issued in the past that permitted pulping and other engineered wood products made with resins and treated with chemicals. Specific to pulping, commenters applied the general definition in the proposed regulations that provided for separation and purification to reason that the pulping of cut timber is merely separation into the component parts of wood—water, cellulose fibers, lignin, and hemicelluloses—through the addition of water and chemicals. Therefore, they argued, the specific rule for timber was more restrictive than the general rule for all natural resources. In contrast, one commenter acknowledged that the production of plywood and other engineered wood products should not generate qualifying income because a non-natural resource (that is, a synthetic adhesive) is a material input in the process that produces engineered wood products.

The final regulations do not adopt commenters’ requests to expand the definition of the processing of timber, but adopt the rule in the proposed regulations without change. As discussed in section I of this Summary of Comments and Explanation of Revisions, the Treasury Department and the IRS interpret the legislative history of section 7704(d)(1)(E) to mean that Congress did not intend to extend processing activities beyond those involved in getting a natural resource such as timber to market in a form generally sold. Potential products made from wood are numerous, and include: pulp, paper and other paper products, certain chemicals (such as tar, tall oil, or turpentine), engineered wood products, lumber, sawdust, wood chips, and furniture. The point where processing turns into manufacturing is definable: the modification of the physical state of wood is a process, whereas the addition of chemicals in an attempt to manipulate the physical or chemical properties of wood is extended processing more akin to manufacturing, and thus beyond the scope of activities intended by Congress to generate qualifying income. The corollary of a field processing plant for timber is a sawmill or pellet mill. Sawmills produce lumber and lumber products (such as bark, sawdust, and wood chips) from felled logs. Pellet mills produce pellets from logs, chipped wood, lumber scraps, sawdust or pulpwood. These processes do not change the wood into a different product. The distinction between processing and manufacturing of timber is demonstrated in the MACRS class lives in Rev. Proc. 87–56, which separate the sawing of stock from logs (24.2 and 24.3) from the manufacture of furniture, pulp, and paper (24.4 and 26.1). Despite commenters’ statements that pulping is like crude oil refining, timber is not commonly understood to be “refined” to a higher level of purity. Timber is simply “processed”; therefore, these regulations do not include timber in the definition of refining.

The proposed regulations provided that transportation was the movement of minerals or natural resources and products of mining, production, processing, or refining, including by pipeline, barge, rail, or truck, except for transportation (not including pipeline transportation) to a place that sells or dispenses to retail customers. Retail customers did not include a person who acquired oil or gas for refining or processing, or a utility. The following activities qualified as transportation under the proposed regulations: (i) providing storage services; (ii) terminalling; (iii) operating gathering systems and custody transfer stations; (iv) operating pipelines, barges, rail, or trucks; and (v) construction of a pipeline only to the extent that a pipe was run to connect a producer or refiner to a preexisting interstate or intrastate line owned by the PTP (interconnect agreements).

Commenters requested both clarification and expansion of the definition of transportation in three main areas. First, commenters asked that the regulations explain who can generate qualifying income from transportation via pipeline and marine shipping. Specifically, different commenters sought assurances that those “operating pipelines” include operators who move the product, owners and lessors who receive income for use of their pipelines, and logistic service providers who schedule the movement of product on pipelines. Similarly, another commenter asked that the regulations specify that transportation under a time charter is a qualifying activity. Under such contractual arrangements, a PTP provides a crew and operates a marine vessel, though the customer (such as an oil and gas company) directs where the product is to be delivered. Essential to this request is the additional proposal that the term “barges” in the proposed regulations be read expansively to include marine transportation via other types of vessels, especially those that move under their own power rather than being pushed or towed.

To transport is “to carry or convey (a thing) from one place to another,” and transportation is “the movement of goods or persons from one place or another by a carrier.” Black’s Law Dictionary (8^th ed. 2004). As a general matter, these final regulations do not require ownership or control of the assets used to perform a listed activity so long as the action being performed is within the definition of a qualifying activity. Following this approach, those performing the physical work to move the product along a pipeline (such as taking delivery of the product, metering quantities, monitoring specifications, and actually controlling the movement of the product) or to transport the product via marine vessel (including operating the vessel under a time charter) are performing a qualifying activity. Also, given the dedicated use of pipelines in the oil and gas industry, these final regulations specifically allow as qualifying income the income owners and lessors receive for the use of their pipelines to transport minerals or natural resources. In contrast, a logistics service provider involved in scheduling services alone neither carries nor conveys, and is therefore not a transporter. A logistics service provider may, however, have qualifying income if it meets the intrinsic test described in further detail in section IV of this Summary of Comments and Explanation of Revisions. Additionally, these final regulations replace the word “barge” with “marine vessel” so as not to limit marine transportation to one type of watercraft.

The second area of concern raised by commenters dealt with the exception for transportation to retail customers. Commenters asked that the regulations clarify that certain transportation to retail customers is a qualifying activity. For example, citing to one sentence in the legislative history that “[i]ncome from any transportation of oil or gas or products thereof by pipeline is treated as qualifying income,” one commenter asserted that Congress intended to include as a qualifying activity the transportation of oil and gas by pipeline directly to homeowners. H.R. Conf. Rep. 100–1104(II), at 18 (1988) (emphasis added). Likewise, many other commenters asserted that Congress intended that the transportation and corresponding marketing of liquefied petroleum gas (primarily propane) to retail customers generate qualifying income. These commenters pointed to floor statements made by Senator Lloyd Bentsen and Representative Dan Rostenkowski after enactment of section 7704, which were specifically referenced in a footnote in the Conference Report to the Technical and Miscellaneous Revenue Act of 1988. See 133 Cong. Rec. S18651 (December 22, 1987), 133 Cong. Rec. H11968 (December 21, 1987), and H.R. Conf. Rep. 100–1104(II), at 18 (1988).

To provide more clarity, these final regulations explain when transportation to a place that sells to retail customers or transportation directly to retail customers is a qualifying activity. Specifically, these final regulations provide that transportation includes the movement of minerals or natural resources, and products produced under processing and refining, via pipeline to a place that sells to retail customers, but do not expand the list of qualifying activities to include the movement of such items via pipeline directly to retail customers. In addition, these final regulations provide that transportation includes the movement of liquefied petroleum gas via trucks, rail cars, or pipeline to a place that sells to retail customers as well as directly to retail customers.

These provisions implement Congressional intent as expressed in the legislative history accompanying the Technical and Miscellaneous Revenue Act of 1988 which provided: “in general, income from transportation of oil and gas and products thereof to a bulk distribution center such as a terminal or a refinery (whether by pipeline, truck, barge or rail) be treated as qualifying income. Income from any transportation of oil or gas or products thereof by pipeline is treated as qualifying income. Except in the case of pipeline transport, however, transportation of oil or gas or products thereof to a place from which it is dispensed or sold to retail customers is generally not intended to be treated as qualifying income. Solely for this purpose, a retail customer does not include a person who acquires the oil or gas for refining or processing, or partially refined or processed products thereof for further refining or processing, nor does a retail customer include a utility providing power to customers. For example, income from transporting refined petroleum products by truck to retail customers is not qualifying income.” H.R. Conf. Rep. 100–1104(II), at 17–18 (1988). A footnote added that “[i]ncome from transportation and marketing of liquefied petroleum gas in trucks and rail cars or by pipeline, however, may be treated as qualifying income,” citing the floor statements identified by commenters. Id.

Although the legislative history supports much of what commenters have asked to be clarified, it does not support the proposal that the transportation by pipeline of oil, gas, and products thereof (other than liquefied petroleum gas) directly to homeowners is qualifying income. Although Congress stated that “any” transportation by pipeline qualifies, when read in context with the remainder of the paragraph, it is clear that Congress was discussing bulk transportation. See also S. Rep. 100–445, at 424 (1988) (“[i]n the case of transportation activities with respect to oil and gas and products thereof, the Committee intends that, in general, income from bulk transportation of oil and gas and products thereof be treated as qualifying income”). This treatment also parallels Congressional intent regarding marketing, which is a qualifying activity “at the level of exploration, development, processing or refining,” but not “to end users at the retail level.” Id.

The third area of comments on transportation were requests to include specific, additional activities in the list of examples, in this case, compression services, liquefaction and regasification, and the sale of renewable identification numbers (RINs). Each of these activities relates directly to the conveyance of certain oil and natural gas products and therefore these final regulations adopt commenters’ suggestions to add them as examples to the list of qualifying transportation activities. Natural gas compression is a mechanical process whereby a volume of natural gas is compressed to a required high pressure in order to transport the gas though pipelines. A compression service provider selects appropriate compression equipment (for example, the number of compressors and the compressor configuration), then installs, operates, services, repairs, and maintains that equipment, typically working on a continuous basis. More than the mere sale of equipment, a compression service company is engaged in transportation activities by making natural gas move from one point to another.

Similarly, liquefaction and regasification are the process of transforming methane from a gas to a liquid (LNG) to facilitate its transportation and storage, and the process of reconverting the liquid to a gas, respectively. The regasified natural gas is fungible with natural gas that has not been liquefied and regasified. Moreover, in 2008, Congress amended section 7704(d)(1)(E) to add that income and gains from the transportation or storage of any fuel described in section 6426(d), which includes compressed or liquefied natural gas, generates qualifying income. See Public Law 110–343, 122 Stat. 3765, Section 208(a), and section 6426(d)(2)(C). Since the transportation and storage of LNG clearly is a qualifying activity, the liquefaction and regasification must also generate qualifying income.

Finally, RINs are part of a Congressionally-mandated program to ensure that transportation fuel sold in the U.S. contains a minimum percentage of renewable fuel. Generally, RINs are assigned to each gallon of renewable fuel, and are separated when the renewable fuel is combined with conventional fuel. Companies who blend such additives into conventional fuels are assigned annual quotas of RINs that they must acquire. Companies who acquire more RINs than needed in any year may sell the surplus to others who have not met their quota. Although it is not a direct, physical conveyance of a mineral or natural resource or product of processing and refining, the Treasury Department and the IRS agree that the sale of RINs gives rise to qualifying income as a part of transportation and marketing activities—that is, additization, as that activity is described in more detail in section III.H.5 of this Summary of Comments and Explanation of Revisions.

In addition to the three areas of comments discussed regarding transportation in this section III.E of this Summary of Comments and Explanation of Revisions, commenters also suggested that the final regulations expand the types of interconnect agreements that are treated as giving rise to qualifying transportation activities. Because these final regulations address all construction activities related to performing section 7704(d)(1)(E) activities in a new section regarding cost reimbursements, construction of pipelines is moved from the section on transportation and those comments are discussed in more detail in section III.H.1 of this Summary of Comments and Explanation of Revisions.

The proposed regulations provided that an activity constituted marketing if it was performed to facilitate sale of minerals or natural resources and products of mining or production, processing, and refining, including by blending additives into fuels. The proposed regulations explained that marketing did not include activities and assets involved primarily in retail sales (sales made in small quantities directly to end users), which included, but were not limited to, operation of gasoline service stations, home heating oil delivery services, and local natural gas delivery services.

In addition to the comments received concerning retail sales of liquid petroleum gas addressed in section III.E of this Summary of Comments and Explanation of Revisions, one commenter recommended revising the definition of marketing to better reflect the common meaning of the word by including the act of selling and other activities designed to encourage sales, including the packaging of products. This same commenter also suggested rewording the exclusion for retail sales so that the regulation is more direct and involves an intent test. The commenter proposed eliminating the concepts relating to “assets” and “involved” in retail sales because they create uncertainty and changing the definition from “sales made in small quantities directly to end users” to “sales to ultimate consumers to meet personal needs, rather than for commercial or industrial uses of the articles sold.”

Adopting some of these suggestions, these final regulations directly state that marketing is the bulk sale of minerals or natural resources, and products produced through processing or refining, and includes activities that facilitate sales (such as packaging). These final regulations continue to provide that marketing generally does not include retail sales. These final regulations do not, however, change the definition of retail sales to create an intent-based test that looks to determine the purpose of the purchase. The final regulations are consistent with the legislative history, which clarified that, “[w]ith respect to marketing of minerals and natural resources (e.g., oil and gas and products therefof [sic]), the Committee intends that qualifying income be income from marketing at the level of exploration, development, processing or refining the mineral or natural resource. By contrast, income from marketing minerals and natural resources to end users at the retail level is not intended to be qualifying income. For example, income from retail marketing with respect to refined petroleum products (e.g., gas station operations) is not intended to be treated as qualifying income.” S. Rep. No. 100–445, at 424 (1988). This legislative history indicates that a small business owner who fills his delivery truck at the gas station before delivering his wares is still an end user at the retail level, even though the gasoline is used for commercial purposes.

The final regulations reserve a paragraph for fertilizer under section 7704(d)(1)(E) activities in anticipation of a new notice of proposed rulemaking that will define fertilizer as well as explain what activities involving fertilizer will generate qualifying income. The Treasury Department and the IRS will address the comment received on fertilizer in those proposed regulations.

The Treasury Department and the IRS received comments regarding certain other activities that are not exclusive to just one section 7704(d)(1)(E) activity, including seeking reimbursement for the costs of performing section 7704(d)(1)(E) activities, receiving income from passive interests, blending, and additization. These final regulations include these activities as qualifying activities, and clarify the extent to which these activities generate qualifying income. This preamble also discusses comments received concerning hedging, and requests further comments.

The list of section 7704(d)(1)(E) activities identified only the overarching pursuits undertaken by businesses engaged in the exploration, development, mining or production, processing, refining, transportation, or marketing of minerals or natural resources. The proposed regulations did not list as section 7704(d)(1)(E) activities the many other activities required to run a business, such as hiring employees, negotiating contracts, or acquiring assets used in the business. Normally those typical, administrative activities are considered to give rise to business costs, and are not understood to be the trade or business that generates income for those in the mineral and natural resource industries. Under the proposed regulations, however, a partnership could demonstrate that it performed intrinsic activities, meaning its activities were so closely tied to section 7704(d)(1)(E) activities that income therefrom should be considered derived from those section 7704(d)(1)(E) activities, and thus be treated as qualifying income. Intrinsic activities included limited, active services that closely supported section 7704(d)(1)(E) activities by being specialized, essential, and significant. The proposed regulations also identified a number of service activities that would not meet the requirements to be considered an intrinsic activity, including legal, financial, consulting, accounting, insurance, and other similar services, or activities that principally involved the design, construction, manufacturing, repair, maintenance, lease, rent, or temporary provision of property. This did not mean that a business performing intrinsic activities was prohibited from engaging in the typical activities required to operate its own business, only that supplying those services to others would not generate qualifying income under section 7704(d)(1)(E) for those businesses.

Commenters asked that the final regulations clarify two issues regarding these general services that are not specific to the mineral and natural resource industries. First, commenters recommended that the section 7704(d)(1)(E) activities be defined to include the functions (such as engineering, construction, operations, maintenance, security, billing, hiring, accounting, and tax financial reporting) that, taken in the aggregate, are necessary for the overall operation of the qualifying activity. Commenters thus recommended that the final regulations reflect more generally that income from performing the functions required for the operation of qualifying assets or qualifying businesses (including cost reimbursements) constitutes qualifying income, even if the operator does not own the underlying assets. As an illustration of this request, one commenter provided the example of a pipeline or processing facility operator that provides all of the services to run assets owned by a third party (such as contracting with customers for the use of the pipeline or processing facility, loading/unloading the product, performing tasks necessary to transport or process the product, metering quantities, and monitoring specifications), but also manages the construction of any assets necessary for the completion of the activities and handles all of the back-office functions such as payroll and other administrative services. Although the costs of providing that work may be imbedded in the charge to its client for operating the pipeline or processing facility, sometimes an operating partnership may instead send its client a bill with a separate line item for construction or back office expenses.

The Treasury Department and the IRS agree with commenters that operating income (including from construction and back-office functions) should constitute qualifying income so long as the activities to which the income is attributable are part of the partnership’s business of performing the section 7704(d)(1)(E) activity. Whether the partnership adds the cost to a general overhead account or provides the client with a separate line item detailing that cost in its bill should not matter—that income is still derived from performing the section 7704(d)(1)(E) activity. A partnership performing a section 7704(d)(1)(E) activity that recoups its costs is markedly different from a business solely performing one of the services identified in the intrinsic activities section that are identified as not essential or not significant. Therefore, to clarify this issue, these final regulations provide that if the partnership is, itself, in the trade or business of performing a section 7704(d)(1)(E) activity, income received to reimburse the partnership for its costs incurred in performing that section 7704(d)(1)(E) activity, whether imbedded in the rate the partnership charges or separately itemized, is qualifying income. Reimbursable costs may include, but are not limited to, the cost of designing, constructing, installing, inspecting, maintaining, metering, monitoring, or relocating an asset used in that section 7704(d)(1)(E) activity, or of providing office functions necessary to the operation of that section 7704(d)(1)(E) activity (such as staffing, purchasing supplies, billing, accounting, and financial reporting). For example, a pipeline operator that charges a customer for its cost to build, repair, or schedule flow on the pipelines that it operates will have qualifying income from such activity whether or not the operator itemizes those costs when it bills the customer.

Because these final regulations address reimbursement to a PTP for the construction of assets used by it to perform a section 7704(d)(1)(E) activity more generally, these final regulations remove the narrow provision under the definition of transportation that listed construction of a pipeline as a qualified activity but only to the extent that the pipe was run to connect a producer or refiner to a preexisting interstate or intrastate line owned by the partnership. Many commenters protested that the provisions were too limited, explaining that the Federal Energy Regulatory Commission, which regulates pipelines, may require pipelines to connect with other pipelines to facilitate the efficient movement of product, and that many other new and existing operations (such as gathering systems, utilities, power generation facilities, refineries, local distribution companies, or other commercial or governmental clients) may also wish to connect to pipelines. Based on the hearings held before the passage of section 7704 and the legislative history, it is clear that Congress was concerned about certain mineral and natural resource partnerships being able to acquire necessary capital to build the assets to be used in their section 7704(d)(1)(E) activities. Building a new facility or pipeline is capital intensive and, to the extent that a partnership passes some of those costs on to the client, the income from the reimbursement of those costs, when received, is a part of the partnership’s income from performing the section 7704(d)(1)(E) activity.

The second issue raised by commenters is an extension of the first. Commenters suggested that management fees earned by a direct or indirect co-owner of a business performing a section 7704(d)(1)(E) activity should be treated as qualifying income. One commenter noted that the partner of the business may provide such legal, financial or accounting services for efficiency purposes or under agreement where one partner performs the section 7704(d)(1)(E) activities while another performs the administrative activities. These final regulations do not adopt this suggestion. To the extent a partner of a PTP is receiving a management fee (as distinguished from a distributive share of partnership income) for such administrative tasks as legal, financial or accounting services, it is no different than any other business providing a service to the PTP. Whether income from the services is qualifying will depend on whether the partner can demonstrate that it is performing an intrinsic activity as discussed in section IV of this Summary of Comments and Explanation of Revisions.

The proposed regulations did not address whether income from hedging transactions was qualifying income. Several commenters noted this and specifically requested guidance on this question. Commenters noted that commodity prices are volatile and PTPs must hedge their risks to ensure consistent cash flows, both from an operational and working capital perspective, and from an investor demand perspective. Commenters recommended that the final regulations provide that income derived from any hedging transactions that are entered into by a PTP in the normal course of its trade or business and that manage the PTP’s risk with respect to price fluctuations of the minerals or natural resources should be included as qualifying income. Other commenters would include income from any hedging transactions entered into by a PTP in order to manage its prudent business concerns, including transactions hedging interest rate risks and foreign currency transactions related to its qualifying activities. One commenter further recommended that a hedge of an aggregate risk with respect to both a qualifying activity and a non-qualifying activity should be considered income from the qualifying activity if substantially all of the risk hedged relates to the qualifying activity.

The Treasury Department and the IRS agree with commenters that hedging income, when it is derived from a section 7704(d)(1)(E) activity, should give rise to qualifying income under section 7704(d)(1)(E). Engaging in hedging activities is a common part of the industry and represents prudent business practice. However, because hedging transactions are generally used to fix the price of property with respect to a section 7704(d)(1)(E) activity, the Treasury Department and the IRS believe that both the income and gains, as well as the deductions and losses, with respect to hedges should be taken into account in determining the income from a section 7704(d)(1)(E) activity. These final regulations reserve on the issue of hedging while the Treasury Department and the IRS consider what types of hedging transactions would result in qualifying income and whether to adjust gross income for such hedging transactions. To that end, the Treasury Department and the IRS request comments on methods to account for the income and gains, as well as the deductions and losses, with respect to hedges. For example, future regulations may generally provide that income, deduction, gain, or loss from a hedging transaction entered into by the partnership primarily to manage risk of price changes or currency fluctuations with respect to ordinary property (as defined in § 1.1221–2(c)(2)) with respect to which qualifying income is derived from a section 7704(d)(1)(E) activity is treated as an adjustment to qualifying income, provided that the transaction is entered into in the ordinary course of the PTP’s business and is clearly identified by the end of the day on which it is entered into. The principles of section 1221(b)(2)(B) and the regulations thereunder, regarding identification, recordkeeping, and the effect of identification and non-identification, would apply to hedging transactions entered into by the PTP.

For example, a partnership might have gain or loss on a forward contract that it enters into to hedge the price risk related to its sale of a commodity with respect to which qualifying income is derived from a qualifying activity. If the partnership has gain that is recognized on the hedge under its method of accounting, then such gain would be treated, for purposes of section 7704(c)(2), as an additional amount realized with respect to the commodity and would be treated under these rules as increasing the amount of qualifying income derived from the qualifying activity. Conversely, if the taxpayer recognizes loss under its accounting method with respect to the hedge, then the loss would be treated, for purposes of section 7704(c)(2), as a decrease in the amount realized on the commodity thus decreasing the qualifying income derived from the qualifying activity.

The Treasury Department and the IRS do not agree, however, that income from hedging with respect to an activity that is not a section 7704(d)(1)(E) activity should give rise to qualifying income under section 7704(d)(1)(E). Other types of hedges, however, may be included under other provisions of section 7704. For example, as noted by some of the commenters, the existing regulations under § 1.7704–3 provide that qualifying income includes (1) income from notional principal contracts (NPC) if the property, income, or cash flow that measures the amount to which the partnership is entitled under the NPC would give rise to qualifying income if held or received directly by the partnership and (2) other substantially similar income from ordinary and routine investments to the extent determined by the Commissioner. See § 1.7704–3(a)(1).

Income from passive interests was not addressed in the proposed regulations. Commenters suggested that income from passive, non-operating economic interests in minerals and natural resources (for example, royalty interests, net profits interests, rights to production payments, delay rental payments, and lease bonus payments) should be qualifying income. One commenter explained that passive economic interest owners have an economic interest in the minerals in place (for example, they are treated as the owner of the mineral or natural resource when it is in fact produced) and a right to share and participate in the proceeds derived from the production of the minerals and natural resources. Another commenter noted that surface damage payments may arise as a part of mining or production. For example, if surface ownership and mineral ownership are separate, a miner may pay royalties to both the surface owner and mineral owner. One commenter explained that several parties may derive income from exploration, development, mining, production, or marketing: (1) owners of passive economic interests that themselves do not engage in the production operations associated with mineral or natural resource properties, but benefit from their respective shares of production revenue; (2) working interest owners (whether or not the “operator”) that are responsible for the activities of exploring for, drilling for, and producing natural resources from the mineral properties, and (3) third-party service providers, who generally do not own an economic interest in the mineral properties, but charge the working interest owners fees or service charges. The commenter noted that the proposed regulations addressed income of working interest owners and third-party service providers, but not those with passive economic interests.

Because income from passive economic interests can be generated at many different stages throughout the process of getting minerals and natural resources to a marketable form, these final regulations include income from passive economic interests in minerals and natural resources as qualifying income.

Commenters raised several questions about the extent to which the blending of the same mineral or natural resource, or products thereof, was a qualifying activity. The proposed regulations referenced some blending activities by treating as a section 7704(d)(1)(E) activity the chemical conversion of the physically separated components of crude oil if one or more of the products of the conversion were recombined with other physically separated components of crude oil in a manner that was necessary to the cost-effective production of gasoline or other fuels. The proposed regulations also included “blending additives into fuel” as a marketing activity.

Commenters noted that terminal operators also perform blending services as a part of their transportation activities, and requested that the regulations be clarified to list blending as a transportation activity. Commenters explained that terminals may blend different grades of crude oil together to achieve the desired grade or quality of crude oil, or they may blend a diluent (such as diesel fuel, or a lighter grade of crude oil) into heavier crude oil to achieve a level of viscosity appropriate for the subsequent mode of transportation. Another commenter stated that refineries also perform some blending activities, and asked that income from such blending be treated as qualifying income. Commenters also raised concerns that the restriction in the proposed regulations to the blending of just fuels does not account for the other products of a refinery that may be produced through blending activities. In addition, one commenter noted that terminals for other natural resources perform blending activities. For example, the commenter explained that coal terminals may mix or homogenize grades of coal from different mines or mining regions with dissimilar characteristics (for example, higher sulfur coal and lower sulfur coal) to achieve coal that meets product specifications.

Expanding on this idea, some commenters asked for clarification that the combination of different minerals and natural resources, or products thereof, should also be a qualifying activity where all products combined are natural resources or products thereof. For example, one commenter suggested that the physical mixing of asphalt with aggregates to produce road paving material should be treated as processing provided that the primary purpose of the mixing is to enhance the inherent use of each of the products mixed. That commenter thought that a product would no longer be considered a natural resource if the product does not retain a majority of the physical and chemical characteristics of the mineral or natural resource from which it was produced.

These final regulations adopt the recommendation that qualifying income should include income from the blending of the same mineral or natural resource, or products thereof. Income from blending is thus added as a type of additional qualifying income because blending may be part of processing, refining, transportation, or marketing. In response to comments, these final regulations also provide that, for purposes of the blending rules in these regulations, products of crude oil and natural gas will be considered as from the same natural resource. These final regulations do not, however, expand the definition of processing or refining to include the combination of different minerals or natural resources, except as permitted under the rules related to additization, which are discussed in section III.H.5 of this Summary of Comments and Explanation of Revisions. Allowing the combination of different natural resources would greatly expand the scope of qualifying activities beyond that intended by Congress, and is akin to additional processing to the point of manufacturing a new product. For example, once asphalt is mixed with rock aggregate, it is no longer a product of a refinery or a product of mineral processing, but has become a new road paving product.

As they did for blending, commenters raised several questions about the extent to which the addition of a minimal amount of different minerals or natural resources or other materials to minerals or natural resources is a qualifying activity. The proposed regulations recognized that some additization was a qualifying activity, but only to the extent it was a marketing activity and only with respect to fuels.

The proposed regulations left undefined what additization included. One commenter recommended that the addition of additives to enhance, preserve, or complement the mineral or natural resource product, such as the chemical treatment of sand, should qualify. Another commenter recommended that additization activities that do not change a natural resource into a new product should give rise to qualifying income whether done as part of processing, refining, transportation, or marketing and no matter the type of product (allowing, for example, additization with respect to lubricants or asphalt).

The Treasury Department and the IRS agree that it is appropriate to treat some additization services as qualifying activities. For example, certain additization may occur in order to safely transport a product (sand terminals, for example, may treat sand with a detergent to prevent dust as the sand travels by rail or truck to its final destination) or to comply with Federal, state, or local regulations concerning product specifications (as, for example, in the case of the addition of dyes to gasoline). However, the Treasury Department and the IRS remain concerned about distinguishing between products of refineries and field facilities, and products of additional processing. Accordingly, and consistent with some of the comments received, these final regulations distinguish between additives that are merely a small addition to a product of a refinery, field facility, or mill, and additives that may change the product into a new or different product. These final regulations thus provide rules regarding additization tailored to crude oil, natural gas, other ores and minerals, and timber.

With respect to crude oil, natural gas, and products thereof, commenters explained that the additives, which are typically not natural resources for the purposes of section 7704, are often required by applicable regulations or otherwise enhance motor fuel blend stock. These additives are added at the terminal because it allows products owned by different customers to be commingled for storage, but then customized for each customer as loaded into carriers for shipment. Typical additives include detergents, dyes, cetane improvers, cold flow improvers, fuel oil stabilizers, isotopic markers, lubricity/conductivity improvers, anti-icing agents, and proprietary gasoline additives. Ethanol is also typically blended into gasoline to satisfy EPA guidelines, and biodiesel is often blended into diesel fuel. Commenters noted that ethanol typically constitutes 10 percent of the blend but can be higher, while biodiesel typically constitutes 20 percent of the blend but can be lower or higher. Other additives typically make up a very small portion of the blended stock (typically less than 1 percent).

Commenters also argued that, just as additives were permitted in the proposed regulations with respect to fuels, additization should also be allowed for other products of oil and natural gas processing and refining. These commenters noted that there is no practical difference between adding ethanol, biodiesel, or other additives into fuels, and adding additives into lubricating oils and waxes. For example, commenters explained that lubricating oils, waxes, and other refined products may be blended together and with additives to provide increased anti-wear protection, reduce friction, extend oil life, improve corrosion protection, give the ability to separate from water, and reduce energy usage. Lubricants may also be mixed with a detergent and a thickener to produce greases in multiple grades and for many uses. These commenters also recommended that additization should not be limited to just a marketing activity as, for example, terminals and refineries both may perform additization activities.

The Treasury Department and the IRS agree that, since additization activities are commonly performed by refineries and by terminals with respect to all products of a refinery, additization should be treated as a qualifying activity that generates qualifying income. These final regulations adopt this change and provide that, to the extent the additives generally constitute less than 5 percent of the total volume for products of natural gas and crude oil and are added into the product by the terminal operator or upstream of the terminal operator, the additization activity generates qualifying income. As previously explained, added ethanol and biodiesel may constitute up to 20 percent of the total volume for products of natural gas and crude oil; therefore, the final regulations provide for a 20 percent threshold for ethanol and biodiesel. Although the Treasury Department and the IRS remain concerned that qualifying income not include the manufacture of new products beyond those generally produced in field facilities or refineries, the Treasury Department and the IRS have concluded that the small amount of additives discussed in some of the comments do not pose a risk if they are consistent with the limitations set forth in the final regulations.

In the case of minerals other than oil and gas, the final regulations provide that the addition of incidental amounts of material such as paper dots to identify shipments, anti-freeze to aid in shipping, or compounds to allay dust as required by law or reduce losses during shipping is permissible.

Regarding timber, one commenter noted that the treatment of lumber and poles with an immaterial amount of additives that protect or enhance the natural resource or that are necessary to meet environmental or regulatory standards should also constitute timber processing. This commenter noted that the proposed regulations included an intent-based test that looks to whether chemicals are added to “manipulate” physical or chemical properties of the timber. The commenter argued that there is no manipulation of physical or chemical properties of the timber in the case of relatively small amounts of additives, such as those that constitute five percent or less of the product. This commenter provided no examples of what types of treatment processes would be required under environmental or regulatory standards for lumber and poles, but did argue that, although wood pellets are commonly made without the addition of any non-timber additives, it is possible that customers or regulators may require the addition of an additive to reduce the emissions profile of wood pellets.

As previously discussed, these final regulations generally allow for small amounts of additives where required in order to comply with Federal, state, or local law when such additives do not rise to the level of a manufacturing activity. As such, the final regulations provide that, for timber, additization of incidental amounts of material as required by law is permissible, to the extent such additions do not create a new product. These final regulations clarify, however, that the application of chemicals and pressure to produce pressure treated wood does not give rise to qualifying income. This is a process generally completed at a separate site from the mill, and creates a new and different manufactured product.

The proposed regulations provided that for purposes of section 7704(d)(1)(E), qualifying income includes only income and gains from qualifying activities with respect to minerals or natural resources. Qualifying activities were defined to include section 7704(d)(1)(E) activities and intrinsic activities. The preamble to the proposed regulations explained that the Treasury Department and the IRS believed that certain limited support activities intrinsic to section 7704(d)(1)(E) activities also gave rise to qualifying income because the income is “derived from” the section 7704(d)(1)(E) activities. The proposed regulations set forth three requirements for a support activity to be intrinsic to a section 7704(d)(1)(E) activity: the activity must be specialized to support the section 7704(d)(1)(E) activity, essential to the completion of the section 7704(d)(1)(E) activity, and require the provision of significant services to support the section 7704(d)(1)(E) activity. The preamble further explained that the Treasury Department and the IRS intended that intrinsic activities constitute active support of section 7704(d)(1)(E) activities, and not merely the supply of goods.

The intrinsic activities provision provided a way for businesses whose activities were not listed as section 7704(d)(1)(E) activities to demonstrate that they were so closely tied to section 7704(d)(1)(E) activities that they should be considered a part of the mineral or natural resource industries, and that their activities therefore generated qualifying income. Because these intrinsic activities were discussed as support or service activities, some commenters mistakenly believed that all service providers that did not own or possess control of the underlying mineral or natural resource (such as a subcontractor) must test whether their activities generated qualifying income solely under the intrinsic activities test, even if the activity being performed was listed as a section 7704(d)(1)(E) activity. For example, one commenter recommended an alternative intrinsic activity standard whereby activities of a service provider would qualify as intrinsic to a section 7704(d)(1)(E) activity if they would have qualified as a section 7704(d)(1)(E) activity, or an indispensable part thereof, if performed directly by the service recipient.

Conversely, one commenter argued that the simplest and most direct way to define what activities are qualifying for purposes of section 7704(d)(1)(E) is to require possession of the mineral or natural resource. This commenter argued that the Treasury Department and the IRS expanded the scope of qualifying income beyond that intended by Congress by accommodating additional support activities such as water delivery and disposal.

Like the proposed regulations, these final regulations do not contain any requirement that a PTP engaged in a section 7704(d)(1)(E) activity must own or possess control of the underlying mineral or natural resource. Such a requirement conflicts with some of the listed 7704(d)(1)(E) activities. For example, a PTP pipeline company may not own the products being transported. Many of the examples of activities defining each of the listed 7704(d)(1)(E) activities can be performed without having ownership or possession of the mineral or natural resource. Furthermore, the legislative history clarified that “[t]he reference provided in the bill to depletable products is intended only to identify the minerals or natural resources and not to identify what income from them is treated as qualifying income. Consequently, whether income is taken into account in determining percentage depletion under section 613 is not necessarily relevant in determining whether such income is qualifying income under section 7704(d).” H.R. Rep. No. 100–795, at 400 (1988). Because the activities listed in section 7704(d)(1)(E) may commonly be performed by persons without ownership of the underlying resource, the ownership requirements in sections 611 and 613 are not relevant in determining whether income is qualifying for purposes of section 7704(d)(1)(E). Finally, section 7704(d)(1)(E) provides that qualifying income is income “derived from” exploration, development, mining or production, processing, refining, transportation, and marketing. The intrinsic activities test applies to those PTPs who engage in activities other than those listed as a section 7704(d)(1)(E) activity but that may receive income “derived from” a section 7704(d)(1)(E) activity. Although the existence of the intrinsic activities test was especially important in the proposed regulations since the list of section 7704(d)(1)(E) activities was exclusive, the test retains purpose in the final regulations because it potentially allows as qualifying some activities that closely support, but do not specifically constitute, an enumerated section 7704(d)(1)(E) activity.

To the extent the commenter who suggested the alternative intrinsic activities standard was also asking that an activity be considered a qualifying activity when a subcontractor performs only a subset of the tasks of a larger qualifying activity, that suggestion ignores the main thrust of section 7704(d)(1)(E), which looks to the activity that is being performed that generates the income received. For example, this commenter argued that, because a refiner may use an air separation unit to separate air into its primary components for use in refining, a taxpayer that is solely engaged in providing air separation unit services to that refiner should have qualifying income. However, the use of air to produce nitrogen and oxygen is clearly not a section 7704(d)(1)(E) activity. Air is not a mineral or natural resource. See sections 7704(d)(1) and 613(b)(7)(B). A refinery may use such gases in its activities, but that does not mean the provision of the air separation unit to create the gases somehow should give rise to qualifying income solely because the nitrogen and oxygen are provided to a refinery. The provision and operation of an air separation unit would only qualify to the extent such activity meets the intrinsic test.

Aside from general criticism that the intrinsic activities provision was too subjective overall and challenging to apply in situations that require a high level of certainty, the remainder of the comments on the intrinsic activities provision requested changes to the requirements of two specific prongs of the test dealing with specialization and significant services, as discussed in sections IV.B and IV.C, respectively, of this Summary of Comments and Explanation of Revisions. The Treasury Department and the IRS received no comments recommending changes to the essential prong of the intrinsic activities test in the proposed regulations, which required that the activity be necessary to (a) physically complete the section 7704(d)(1)(E) activity (including in a cost-effective manner, such as by making the activity economically viable), or (b) comply with Federal, state, or local law regulating the section 7704(d)(1)(E) activity. These final regulations thus adopt the essential prong of the intrinsic activities test with no changes.

The proposed regulations provided that an activity was specialized if the partnership provided personnel to perform or support a section 7704(d)(1)(E) activity and those personnel received training unique to the mineral or natural resource industry that was of limited utility other than to perform or support a section 7704(d)(1)(E) activity (hereinafter “specialized personnel requirement”). In addition, to the extent that the activity included the sale, provision, or use of property, the proposed regulations required that either: (1) the property was primarily tangible property that was dedicated to, and had limited utility outside of, section 7704(d)(1)(E) activities and was not easily converted to another use (hereinafter “specialized property requirement”); or (2) the property was used as an injectant to perform a section 7704(d)(1)(E) activity that was also commonly used outside of section 7704(d)(1)(E) activities (such as water, lubricants, and sand) and, as part of the activity, the partnership also collected and cleaned, recycled, or otherwise disposed of the injectant after use in accordance with Federal, state, or local regulations concerning waste products from mining or production activities (hereinafter “injectants exception”).

Commenters identified concerns with all three parts of the specialization prong. Regarding the specialized personnel requirement, one commenter said it was unclear how much training was necessary for a skill to be considered specialized. Regarding the specialized property requirement, the same commenter criticized as vague the language about property having limited utility outside section 7704(d)(1)(E). Other commenters argued that the specialized property requirement should be removed entirely or that the use of specialized property should be treated as an indication that a certain activity was specialized rather than being required. They explained that service companies use a lot of equipment, some of which would not be specialized (for example, telephones, hammers, or bulldozers) in performing their duties. Finally, one commenter recommended that the specialization prong be amended to recognize that activities may be specialized if they support a section 7704(d)(1)(E) activity in a remote or difficult environment (for example, marine locations). This commenter described as an example of such activities allowing access to and use of its marine docks and terminals, as a support base for unrelated third-party oilfield service companies selling products and providing services in the Gulf of Mexico in support of production of oil and gas.

Overall, the Treasury Department and the IRS remain concerned that the final regulations provide a means to differentiate between the mere provision of general services, goods, or equipment to others and the active support of a section 7704(d)(1)(E) activity. The final regulations thus do not adopt the recommendation that the test be amended to include any support provided for section 7704(d)(1)(E) activities performed in remote or difficult environments. Support is a vague term that could include the provision of food or everyday supplies to workers on a marine platform. In addition, merely making docks available for use by third parties does not give rise to qualifying income under section 7704(d)(1)(E). The Treasury Department and the IRS continue to consider the specialized personnel and specialized property requirements important in insuring that the services or goods provided have a clear nexus to section 7704(d)(1)(E) activities.

The final regulations also do not adopt the suggestion to provide requirements for how much training is necessary to meet the specialized personnel requirement. Instead, these regulations retain the provision that personnel must have received training unique to the mineral or natural resource industry. The particular industry at issue would determine the type and amount of training necessary to perform the support activity. However, the Treasury Department and the IRS agree with commenters that the specialized property requirement in the proposed regulations was overly broad. These final regulations specifically provide that the use of non-specialized property typically used incidentally in operating a business will not cause a PTP to fail the specialized property requirement. However, these final regulations retain the restrictions in the specialized personnel requirement and the specialized property requirement that training provided for and property (other than property typically used incidentally in operating a business) involved in the activity must not have applications outside of section 7704(d)(1)(E) activities.

Commenters provided many suggestions for changes regarding the injectants exception. Multiple commenters recommended that sand should be removed from the examples of injectants because it is a natural resource, and therefore the bulk sale or wholesale of sand would, in itself, qualify as a section 7704(d)(1)(E) activity—marketing. These final regulations adopt this recommendation and remove sand as an example of an injectant in the injectants exception.

Another commenter recommended expanding the injectants exception to encompass the supply, cleaning, or recycling of all products required for any section 7704(d)(1)(E) activity, not just injectants. This commenter provided as an example the supply and recycling of sulfuric acid, used as a catalyst for purposes of alkylation (a process used to produce alkylates). These final regulations do not adopt this suggestion. A general rule that allows for supply, cleaning, and recycling of any good provided to others engaged in section 7704(d)(1)(E) activities is too broad and contrary to the stated goal of the intrinsic test in differentiating section 7704(d)(1)(E) support activities from the mere provision of a good. The Treasury Department and the IRS continue to consider it appropriate to limit the exception to just injectants because Federal, state, and local law require that producers recycle or otherwise properly dispose of injectants, such as water, after use in mining and production activities. Oilfield service companies providing that service are thus a required part of the mining and production process—their income is thus “derived from” the production activity. Expanding the injectants exception as requested would lead to many industrial waste recycling activities potentially being included in what is intended to be a limited exception for a legally required step in section 7704(d)(1)(E) activities. Thus, these regulations do not adopt this suggestion.

Commenters also had a number of comments specifically concerning water under the injectants exception. Multiple commenters noted that, although they generally supported the proposed regulations in their effort to provide a framework for the types of oilfield service activities that would generate qualifying income, as a practical matter, they believed that a requirement that a PTP perform both the water delivery and disposal activities at each well or development site in order for that water delivery service to qualify would be satisfied infrequently. These commenters also argued that, so long as they also are engaged in performing disposal services, their business model is not merely supplying a good, that is, water. Multiple commenters recommended that the injectants exception should not require that the product (in particular, water) that is delivered must be the product that is picked up and recycled—what these commenters described as a “well by well” approach. These commenters explained that it is common in the industry for a well operator to source its water supply and disposal service requirements with multiple providers and that it may be difficult or impossible for a PTP to satisfy the necessary “well by well” factual determination. Accordingly, commenters suggested several alternatives to the “well by well” approach.

One commenter recommended that water delivery services should qualify as intrinsic activities only if exclusively provided by a PTP to those engaged in one or more section 7704(d)(1)(E) activities in cases where the PTP’s operations also include conducting necessary water disposal services on an ongoing or frequent basis, though not necessarily in the same location. Another commenter recommended that the injectants exception be met if the partnership providing the injectant also provides other specialized services with respect to such injectant at the wellsite, such as transporting the water to smaller temporary storage facilities at the wellsite, treating the water prior to it going downhole, and monitoring and testing the utilization of water throughout the transfer and pressure pumping process. This commenter alternatively recommended that the regulations only require that there be delivery and clean up in the same geographic area (a “basin by basin” approach). Others suggested that mere water delivery should qualify so long as the water is delivered to those engaged in one or more section 7704(d)(1)(E) activities, or the water enhances the producers’ ability to produce oil or gas (as opposed to being provided for other purposes). Finally, one commenter argued that the regulations should not require disposal in compliance with Federal, state, or local regulations since making a tax determination contingent on such compliance introduces a standard that would be difficult to administer.

The Treasury Department and the IRS do not find support for the argument that the mere delivery of water qualifies. Section 7704(d)(1) is clear that a mineral or natural resource does not include water; thus, income from the simple marketing and transportation of water is not qualifying income. As explained previously, the Treasury Department and the IRS have concluded that companies that provide water with legally required disposal services have a strong nexus to a section 7704(d)(1)(E) activity (in particular, mining and production). Some commenters share that belief and support the efforts of the Treasury Department and the IRS, agreeing that there is a difference between companies that simply provide water (the mere provision of a good) and those that provide both water and specialized services. Nor do the final regulations adopt the suggestion to remove the language that the injectants are disposed after use in accordance with Federal, state, or local regulations concerning waste products from mining or production activities. Although, for tax compliance purposes, the IRS will generally not confirm that the PTP actually disposed of the injectants as required under Federal, state, or local law, the injectants exception is based on the PTP providing disposal services where required by Federal, state, or local law.

The Treasury Department and the IRS agree with commenters that the injections exception should be revised to account for industry practice in which a miner or producer may not hire the same company to provide both water delivery and disposal services. Accordingly, these final regulations instead adopt the “basin by basin” approach recommended in comments—so long as the PTP provides the water exclusively to those engaged in section 7704(d)(1)(E) activities and both delivers and recycles within the same geographic area, the PTP’s income from such activities is qualifying. The Treasury Department and the IRS have concluded that this requirement would provide a clear, administrable rule concerning when water delivery is not merely the delivery of a good, but part of the provision of specialized disposal services.

The proposed regulations provided that an activity requires significant services to support the section 7704(d)(1)(E) activity if it must be conducted on an ongoing or frequent basis by the partnership’s personnel at the site or sites of the section 7704(d)(1)(E) activities. Alternatively, those services could be conducted offsite if the services are performed on an ongoing or frequent basis and are offered exclusively to those engaged in one or more section 7704(d)(1)(E) activities. Whether services are conducted on an ongoing or frequent basis is determined based on all the facts and circumstances, including recognized best practices in the relevant industry. Partnership personnel performed significant services only if those services were necessary for the partnership to perform an activity that is essential to the section 7704(d)(1)(E) activity, or to support the section 7704(d)(1)(E) activity. Finally, an activity did not constitute significant services with respect to a section 7704(d)(1)(E) activity if the activity principally involved the design, construction, manufacturing, repair, maintenance, lease, rent, or temporary provision of property.

One commenter argued that a facts and circumstances test to determine whether services are conducted on an ongoing basis is vague and would be subject to various interpretations. Another commenter recommended the removal of the significant services prong completely, arguing that the frequency with which an activity is performed is not relevant to determining whether an activity should qualify. Instead, the test should focus on the needs and activities of the operator, rather than the activities of the service provider. One commenter suggested that the proposed regulations wrongly listed repair and maintenance as activities that do not constitute significant services with respect to a section 7704(d)(1)(E) activity, arguing that the repair and maintenance of equipment and facilities are often required by the operator on a near-continuous basis under typical services agreements.

The Treasury Department and the IRS do not find support for the contention that the test should solely focus on the needs of the operator. Section 7704(d)(1) applies to determine whether a PTP’s income is qualifying income; therefore, the focus of these regulations is on the activities performed by the PTP giving rise to the income at issue. The significant services prong is an important part of determining whether the activity performed by a support services PTP has the required nexus with a section 7704(d)(1)(E) activity. As such, these final regulations do not adopt these changes and retain the “significant services” prong of the intrinsic services test as well as the statement that significant services do not include an activity principally involving repair or maintenance of property.

One commenter recommended that the restriction that services conducted offsite must be offered exclusively to those engaged in performing section 7704(d)(1)(E) activities should be removed, since activities such as clean-up and disposal happen offsite and may be performed for service recipients other than those engaged in section 7704(d)(1)(E) activities. These final regulations modify this provision to provide that services may be conducted offsite if the services are offered to those engaged in one or more section 7704(d)(1)(E) activities. If the services are monitoring services, those services must be offered exclusively to those engaged in one or more section 7704(d)(1)(E) activities.

Finally, commenters also expressed concerns that it was not clear whether services are counted for purposes of the personnel requirement if they are provided by an affiliate, subcontractor, or independent contractor. These commenters noted that it is common for PTPs to work through related companies and subcontractors. One commenter recommended that the definition of “qualifying activities” in the regulations make clear that an activity is no less a qualifying activity because it is performed by a subcontractor or consists of a subset of the tasks of a larger qualifying activity.

The Treasury Department and the IRS agree that a PTP should be able to meet the personnel requirement through affiliates or subcontractors in addition to the PTP’s own employees. This is true for purposes of satisfying the specialization prong (including determining whether the personnel have received specialized training) or the significant services prong. Accordingly, the final regulations adopt this change and clarify that these prongs can be met through employees of affiliates or subcontractors, so long as they are being compensated by the PTP.

The proposed regulations provided that, except as otherwise provided, the regulations would apply to income earned by a partnership in a taxable year beginning on or after the date the final regulations are published in the Federal Register. An exception was made for certain income earned during a transition period, which would end on the last day of the partnership’s taxable year that included the date that is ten years after the date the final regulations are published in the Federal Register (the Transition Period). That exception provided that a partnership could treat income from an activity as qualifying income during the Transition Period if: (a) the partnership received a private letter ruling from the IRS holding that the income from that activity is qualifying income; (b) prior to the publication of the final regulations, the partnership was publicly traded, engaged in the activity, and treated the activity as giving rise to qualifying income under section 7704(d)(1)(E), and that income was qualifying income under the statute as reasonably interpreted prior to the issuance of the proposed regulations; or (c) the partnership is publicly traded and engages in the activity after the issuance of the proposed regulations but before the date the final regulations are published in the Federal Register and the income from that activity is qualifying income under the proposed regulations.

Commenters objected that the Transition Period is not sufficient and that the IRS should allow PTPs that have received favorable PLRs that are contrary to these final regulations to continue to rely on them permanently. They argued that revoking a PLR sets a bad precedent that will cause taxpayers and investors not to rely on PLRs. They also argued that the revocation of a PLR would hurt them economically and would harm investors. Finally, some commenters requested that the final regulations clarify that a technical termination of a partnership under section 708(b)(1)(B) does not end the Transition Period.

The Transition Period is a reasonable amount of time for PTPs to rearrange their affairs as necessary and is consistent with comments made in Congress concerning the ten-year transition relief granted when section 7704(d)(1)(E) was added in 1987. The IRS may revoke a PLR when the letter is found to be in error or not in accord with the current views of the Service, or there is a material change in fact. If the revocation is as a result of an error or a change in view, this revocation may occur through the issuance of final regulations. See Section 11.04 of Rev. Proc. 2016–1, 2016–1 I.R.B. 1. Therefore, the final regulations do not adopt the suggestion that the IRS permanently allow PTPs with favorable PLRs that are contrary to these final regulations to continue to rely on them. The final regulations do, however, adopt the request for clarification that a technical termination does not end the Transition Period. This addition is consistent with statements made concerning the original 10-year transition period provided by Congress when section 7704(d)(1)(E) was added. See Joint Comm. on Taxation, 100^th Cong., Description of the Technical Corrections Act of 1988 (H.R. 4333 and S. 2238), JCS–10–88, at 412 (1988) (“[i]t is intended that a publicly traded partnership not be treated as ceasing to be an existing partnership solely by reason of a termination of the partnership (within the meaning of section 708) caused by the sale or exchange through trading of 50 percent or more of the partnership interests.”)

(a) In general. For purposes of section 7704(d)(1)(E), qualifying income is income and gains from qualifying activities with respect to minerals or natural resources as defined in paragraph (b) of this section. Qualifying activities are section 7704(d)(1)(E) activities (as described in paragraph (c) of this section) and intrinsic activities (as described in paragraph (d) of this section).

(b) Mineral or natural resource. The term mineral or natural resource (including fertilizer, geothermal energy, and timber) means any product of a character with respect to which a deduction for depletion is allowable under section 611, except that such term does not include any product described in section 613(b)(7)(A) or (B) (soil, sod, dirt, turf, water, mosses, or minerals from sea water, the air, or other similar inexhaustible sources). For purposes of this section, the term mineral or natural resource does not include industrial source carbon dioxide, fuels described in section 6426(b) through (e), any alcohol fuel defined in section 6426(b)(4)(A), or any biodiesel fuel as defined in section 40A(d)(1).

(c) Section 7704(d)(1)(E) activities—(1) Definition. Section 7704(d)(1)(E) activities include the exploration, development, mining or production, processing, refining, transportation, or marketing of any mineral or natural resource. Solely for purposes of section 7704(d), such terms are defined as provided in this paragraph (c).

(2) Exploration. An activity constitutes exploration if it is performed to ascertain the existence, location, extent, or quality of any deposit of mineral or natural resource before the beginning of the development stage of the natural deposit including by—

(i) Drilling an exploratory or stratigraphic type test well;

(ii) Conducting drill stem and production flow tests to verify commerciality of the deposit;

(iii) Conducting geological or geophysical surveys;

(iv) Interpreting data obtained from geological or geophysical surveys; or

(v) For minerals, testpitting, trenching, drilling, driving of exploration tunnels and adits, and similar types of activities described in Rev. Rul. 70–287 (1970–1 CB 146), (see § 601.601(d)(2)(ii)(b) of this chapter) if conducted prior to development activities with respect to the minerals.

(3) Development. An activity constitutes development if it is performed to make accessible minerals or natural resources, including by—

(i) Drilling wells to access deposits of minerals or natural resources;

(ii) Constructing and installing drilling, production, or dual purpose platforms in marine locations, or any similar supporting structures necessary for extraordinary non-marine terrain (such as swamps or tundra);

(iii) Completing wells, including by installing lease and well equipment, such as pumps, flow lines, separators, and storage tanks, so that wells are capable of producing oil and gas, and the production can be removed from the premises;

(iv) Performing a development technique such as, for minerals other than oil and natural gas, stripping, benching and terracing, dredging by dragline, stoping, and caving or room-and-pillar excavation, and for oil and natural gas, fracturing; or

(v) Constructing and installing gathering systems and custody transfer stations.

(4) Mining or production. An activity constitutes mining or production if it is performed to extract minerals or natural resources from the ground including by operating equipment to extract minerals or natural resources from mines and wells, or to extract minerals or natural resources from the waste or residue of prior mining or production allowable under this section. The recycling of scrap or salvaged metals or minerals from previously manufactured products or manufacturing processes is not considered to be the extraction of ores or minerals from waste or residue.

(5) Processing. An activity constitutes processing if it is performed to convert raw mined or harvested products or raw well effluent to substances that can be readily transported or stored, as described in this paragraph (c)(5).

(i) Natural gas. An activity constitutes processing of natural gas if it is performed to—

(A) Purify natural gas, including by removal of oil or condensate, water, or non-hydrocarbon gases (such as carbon dioxide, hydrogen sulfide, nitrogen, and helium); and

(B) Separate natural gas into its constituents which are normally recovered in a gaseous phase (methane and ethane) and those which are normally recovered in a liquid phase (propane, butane, pentane, and heavier streams).

(ii) Crude oil. An activity constitutes processing of crude oil if it is performed to separate produced fluids by passing crude oil through mechanical separators to remove gas, placing crude oil in settling tanks to recover basic sediment and water, dehydrating crude oil, and operating heater-treaters that separate raw oil well effluent into crude oil, natural gas, and salt water.

(iii) Ores and minerals other than natural gas or crude oil. An activity constitutes processing of ores and minerals other than natural gas or crude oil if it meets the definition of mining processes under § 1.613–4(f)(1)(ii), without regard to § 1.613–4(f)(2)(iv).

(iv) Timber. An activity constitutes processing of timber if it is performed to modify the physical form of timber, including by the application of heat or pressure to timber, without adding any foreign substances. Processing of timber does not include activities that add chemicals or other foreign substances to timber to manipulate its physical or chemical properties, such as using a digester to produce pulp. Products that result from timber processing include wood chips, sawdust, rough lumber, kiln-dried lumber, veneers, wood pellets, wood bark, and rough poles. Products that are not the result of timber processing include pulp, paper, paper products, treated lumber, oriented strand board/plywood, and treated poles.

(6) Refining. An activity constitutes refining if the activity is set forth in this paragraph (c)(6).

(i) Natural gas and crude oil. (A) The refining of natural gas and crude oil includes the further physical or chemical conversion or separation processes of products resulting from activities listed in paragraph (c)(5)(i) and (ii) of this section, and the blending of petroleum hydrocarbons, to the extent they give rise to a product listed in paragraph (c)(5)(i) or (ii) of this section or to the products of a type produced in a petroleum refinery or natural gas processing plant listed in this paragraph (c)(6)(i)(A). Refining of natural gas and crude oil also includes the further physical or chemical conversion or separation processes and blending of the products listed in this paragraph (c)(6)(i)(A), to the extent that the resulting product is also listed in this paragraph (c)(6)(i)(A). The following products are of a type produced in a petroleum refinery or natural gas processing plant:

(B) For purposes of this section, the products listed in this paragraph (c)(6)(i)(B) are not products of refining:

(1) Heat, steam, or electricity produced by processing or refining.

(2) Products that are obtained from third parties or produced onsite for use in the refinery, such as hydrogen, if excess amounts are sold.

(3) Any product that results from further chemical change of a product listed in paragraph (c)(6)(i)(A) of this section that does not result in the same or another product listed in paragraph (c)(6)(i)(A) of this section (for example, production of petroleum coke from heavy (refinery) residuum qualifies, but any upgrading of petroleum coke (such as to calcined coke) does not qualify because it is further chemically changed and does not result in the same or another product listed in paragraph (c)(6)(i)(A) of this section).

(4) Plastics or similar petroleum derivatives.

(ii) Ores and minerals other than natural gas or crude oil. (A) An activity constitutes refining of ores and minerals other than natural gas or crude oil if it is one of the various processes performed subsequent to mining processes (as defined in paragraph (c)(5)(iii) of this section) to eliminate impurities or foreign matter and which are necessary steps in achieving a high degree of purity from metallic ores and minerals which are not customarily sold in the form of the crude mineral product, as specified in paragraph (c)(6)(ii)(B) of this section. Refining processes include: fine pulverization, electrowinning, electrolytic deposition, roasting, thermal or electric smelting, or substantially equivalent processes or combinations of processes used to separate or extract the specified metals listed in paragraph (c)(6)(ii)(B) of this section from the ore for the primary purpose of producing a purer form of the metal, as for example the smelting of concentrates to produce Doré bars or refining of blister copper.

(B) For purposes of this section, the specified metallic ores or minerals which are not customarily sold in the form of the crude mineral product are—

(1) Lead;

(2) Zinc;

(3) Copper;

(4) Gold;

(5) Silver; and

(6) Any other ores or minerals that the Commissioner may identify through published guidance.

(C) Refining does not include the introduction of additives that remain in the metal, for example, in the manufacture of alloys of gold. Also, the application of nonmining processes as defined in § 1.613–4(g) in order to produce a specified metal that is considered a waste or by-product of production from a non-specified mineral deposit is not considered refining for purposes of this section.

(7) Transportation—(i) General rule. An activity constitutes transportation if it is performed to move minerals or natural resources, and products under paragraph (c)(4), (5), or (6) of this section, including by pipeline, marine vessel, rail, or truck. Except as provided in paragraph (c)(7)(ii) of this section, transportation does not include the movement of minerals or natural resources, and products produced under paragraph (c)(4), (5), or (6) of this section, directly to retail customers or to a place that sells or dispenses to retail customers. Retail customers do not include a person who acquires oil or gas for refining or processing, or a utility. Transportation includes the following activities:

(A) Providing storage services.

(B) Providing terminalling services, including the following: receiving products from pipelines, marine vessels, railcars, or trucks; storing products; loading products to pipelines, marine vessels, railcars, or trucks for distribution; testing and treating, as well as blending and additization, if income from such activities would be qualifying income pursuant to paragraph (c)(10)(iv) and (v) of this section; and separating and selling excess renewable identification numbers acquired as part of additization services to comply with environmental regulations.

(C) Moving or carrying (whether by owner or operator) products via pipelines, gathering systems, and custody transfer stations.

(D) Operating marine vessels (including time charters), railcars, or trucks.

(E) Providing compression services to a pipeline.

(F) Liquefying or regasifying natural gas.

(ii) Transportation to retail customers or to a place that sells to retail customers. Transportation includes the movement of minerals or natural resources, and products under paragraph (c)(4), (5), or (6) of this section, via pipeline to a place that sells to retail customers. Transportation also includes the movement of liquefied petroleum gas via trucks, rail cars, or pipeline to a place that sells to retail customers or directly to retail customers.

(8) Marketing—(i) General rule. An activity constitutes marketing if it is the bulk sale of minerals or natural resources, and products under paragraph (c)(4), (5), or (6) of this section. Except as provided in paragraph (c)(8)(ii) of this section, marketing does not include retail sales (sales made in small quantities directly to end users), which includes the operation of gasoline service stations, home heating oil delivery services, and local natural gas delivery services.

(ii) Retail sales of liquefied petroleum gas. Retail sales of liquefied petroleum gas are included in marketing.

(iii) Certain activities that facilitate sale. Marketing also includes certain activities that facilitate sales that constitute marketing under paragraphs (c)(8)(i) and (ii) of this section, including packaging, as well as and blending and additization, if income from blending and additization would be qualifying income pursuant to paragraph (c)(10)(iv) and (v) of this section.

(9) Fertilizer. [Reserved]

(10) Additional activities. The following types of income as described in paragraph (c)(10)(i) through (v) of this section will be considered derived from a section 7704(d)(1)(E) activity.

(i) Cost reimbursements. If the partnership is in the trade or business of performing a section 7704(d)(1)(E) activity, qualifying income includes income received to reimburse the partnership for its costs in performing that section 7704(d)(1)(E) activity, whether imbedded in the rate the partnership charges or separately itemized. Reimbursable costs may include the cost of designing, constructing, installing, inspecting, maintaining, metering, monitoring, or relocating an asset used in that section 7704(d)(1)(E) activity, or providing office functions necessary to the operation of that section 7704(d)(1)(E) activity (such as staffing, purchasing supplies, billing, accounting, and financial reporting). For example, a pipeline operator that charges a customer for its cost to build, repair, or schedule flow on the pipelines that it operates will have qualifying income from such activity whether or not it itemizes those costs when it bills the customer.

(ii) Hedging. [Reserved]

(iii) Passive Interests. Qualifying income includes income and gains from a passive interest or non-operating interest, including production royalties, minimum annual royalties, net profits interests, delay rentals, and lease-bonus payments, if the interest is in a mineral or natural resource as defined in paragraph (b) of this section. Payments received on a production payment will not be qualifying income if they are properly treated as loan payments under section 636.

(iv) Blending. Qualifying income includes income and gains from performing blending activities or services with respect to products under paragraph (c)(4), (5), or (6) of this section, so long as the products being blended are component parts of the same mineral or natural resource. For purposes of this paragraph (c)(10)(iv), products of oil and natural gas will be considered as from the same natural resource. Blending does not include combining different minerals or natural resources or products thereof together. However, see paragraph (c)(10)(v) of this section for rules concerning additization.

(v) Additization. Qualifying income includes income and gains from providing additization services with respect to products under paragraph (c)(4), (5), or (6) of this section to the extent specifically permitted in this paragraph (c)(10)(v). The addition of additives described in paragraph (c)(10)(v)(A) through (C) of this section is permissible if the additives aid in the transportation of a product, enhance or protect the intrinsic properties of a product, or are necessary as required by federal, state, or local law (for example, to meet environmental standards), but only if such additives do not create a new product.

(A) The addition of additives to products of natural gas and crude oil is permissible, provided that such additives constitute less than 5 percent (except that ethanol or biodiesel may be up to 20 percent) of the total volume for products of natural gas and crude oil and are added into the product by the terminal operator or upstream of the terminal operator.

(B) In the case of ores and minerals other than natural gas or crude oil, the addition of incidental amounts of material such as paper dots to identify shipments, anti-freeze to aid in shipping, or compounds to allay dust as required by law or reduce losses during shipping is permissible.

(C) In the case of timber, additization of incidental amounts to comply with government regulations is permissible, to the extent such additization does not create a new product. For example, the pressure treatment of wood is impermissible because it creates a new product.

(d) Intrinsic activities—(1) General requirements. An activity is an intrinsic activity only if the activity is specialized to support a section 7704(d)(1)(E) activity, is essential to the completion of the section 7704(d)(1)(E) activity, and requires the provision of significant services to support the section 7704(d)(1)(E) activity. Whether an activity is an intrinsic activity is determined on an activity-by-activity basis.

(2) Specialization. An activity is a specialized activity if—

(i) The partnership provides personnel (including employees of the partnership, an affiliate, subcontractor, or independent contractor performing work on behalf of the partnership) to support a section 7704(d)(1)(E) activity and those personnel have received training in order to support the section 7704(d)(1)(E) activity that is unique to the mineral or natural resource industry and of limited utility other than to perform or support a section 7704(d)(1)(E) activity; and

(ii) To the extent that the activity involves the sale, provision, or use of specific property, either—

(A) The property is primarily tangible property that is dedicated to, and has limited utility outside of, section 7704(d)(1)(E) activities and is not easily converted (as determined based on all the facts and circumstances, including the cost to convert the property) to another use other than supporting or performing the section 7704(d)(1)(E) activities (except that the use of non-specialized property typically used incidentally in operating a business will not cause a partnership to fail this paragraph (d)(2)(ii)(A)); or

(B) If the property is used as an injectant to perform a section 7704(d)(1)(E) activity that is also commonly used outside of section 7704(d)(1)(E) activities (such as water and lubricants), the partnership provides the injectants exclusively to those engaged in section 7704(d)(1)(E) activities; the partnership is also in the trade or business of collecting, cleaning, recycling, or otherwise disposing of injectants after use in accordance with Federal, state, or local regulations concerning waste products from mining or production activities; and the partnership operates its injectant delivery and disposal services within the same geographic area.

(3) Essential. (i) An activity is essential to the section 7704(d)(1)(E) activity if it is required to—

(A) Physically complete a section 7704(d)(1)(E) activity (including in a cost-effective manner, such as by making the activity economically viable), or

(B) Comply with Federal, state, or local law regulating the section 7704(d)(1)(E) activity.

(ii) Legal, financial, consulting, accounting, insurance, and other similar services do not qualify as essential to a section 7704(d)(1)(E) activity.

(4) Significant services. (i) An activity requires significant services to support the section 7704(d)(1)(E) activity if those services must be conducted on an ongoing or frequent basis by the partnership’s personnel at the site or sites of the section 7704(d)(1)(E) activities. Alternatively, those services may be conducted offsite if the services are performed on an ongoing or frequent basis and are offered to those engaged in one or more section 7704(d)(1)(E) activities. If the services are monitoring, those services must be offered exclusively to those engaged in one or more section 7704(d)(1)(E) activities. Whether services are conducted on an ongoing or frequent basis is determined based on all the facts and circumstances, including recognized best practices in the relevant industry.

(ii) Personnel perform significant services only if those services are necessary for the partnership to perform an activity that is essential to the section 7704(d)(1)(E) activity, or to support the section 7704(d)(1)(E) activity. Personnel include employees of the partnership, an affiliate, subcontractor, or independent contractor performing work on behalf of the partnership.

(iii) Services are not significant services with respect to a section 7704(d)(1)(E) activity if the services principally involve the design, construction, manufacturing, repair, maintenance, lease, rent, or temporary provision of property.

(e) Interpretations of section 611 and section 613. This section and interpretations of this section have no effect on interpretations of sections 611 and 613, or other sections of the Code, or the regulations thereunder; however, this section incorporates some of the interpretations under section 611 and 613 and the regulations thereunder as provided in this section.

(f) Examples. The following examples illustrate the provisions of this section:

Example 1. Petrochemical products sourced from an oil and gas well. (i) Z, a publicly traded partnership, chemically converts a mixture of ethane and propane (obtained from physical separation of natural gas) into ethylene and propylene through use of a steam cracker. Z sells the ethylene and propylene in bulk to a third party.

(ii) Ethylene and propylene are products of refining as provided in paragraph (c)(6)(i) of this section; therefore, Z is engaged in a section 7704(d)(1)(E) activity. The income Z receives from the sale of ethylene and propylene is qualifying income for purposes of section 7704(d)(1)(E).

Example 2. Petroleum streams chemically converted into refinery grade olefins byproducts. (i) Y, a publicly traded partnership, owns a petroleum refinery. The refinery physically separates crude oil, obtaining heavy gas oil. The refinery then uses a catalytic cracking unit to chemically convert the heavy gas oil into a liquid stream suitable for gasoline blending and a gas stream containing ethane, ethylene, and other gases. The refinery also further physically separates the gas stream, resulting in refinery-grade ethylene. Y sells the ethylene in bulk to a third party.

(ii) Y’s activities give rise to products of refining as provided in paragraph (c)(6)(i) of this section; therefore, Y is engaged in a section 7704(d)(1)(E) activity. The income Y receives from the sales of ethylene is qualifying income for purposes of section 7704(d)(1)(E).

Example 3. Converting methane gas into synthetic fuels through chemical change. (i) Y, a publicly traded partnership, chemically converts methane into methanol and synthesis gas, and further chemically converts those products into gasoline and diesel fuel. Y receives income from bulk sales of gasoline and diesel created during the conversion processes, as well as from sales of methanol.

(ii) With respect to the production of gasoline or diesel from methane, gasoline and diesel are products of refining as provided in paragraph (c)(6)(i) of this section; therefore, Y is engaged in a section 7704(d)(1)(E) activity. Y’s income from the sale of gasoline and diesel is qualifying income for purposes of section 7704(d)(1)(E).

(iii) The income from the sale of methanol, an intermediate product in the conversion process, is not qualifying income for purposes of section 7704(d)(1)(E) because methanol is not a product of processing or refining as defined in paragraph (c)(5) and (6) of this section.

Example 4. Converting methanol into gasoline and diesel. (i) Assume the same facts as in Example 3 of this paragraph (f), except Y purchases methanol and synthesis gas and chemically converts the methanol and synthesis gas into gasoline and diesel.

(ii) The chemical conversion of methanol and synthesis gas into gasoline and diesel is not refining as provided in paragraph (c)(6)(i) of this section because it is not the physical or chemical conversion or the separation or blending of products listed in paragraph (c)(6)(i)(A) of this section. Accordingly, the income from the sales of the gasoline and diesel is not qualifying income for purposes of section 7704(d)(1)(E).

Example 5. Delivery of refined products. (i) X, a publicly traded partnership, sells diesel to a government entity at wholesale prices and delivers those goods in bulk.

(ii) X’s sale of a refined product to the government entity is a section 7704(d)(1)(E) activity because it is a bulk transportation and sale as described in paragraph (c)(7) and (8) of this section and is not a retail sale.

Example 6. Constructing a pipeline. (i) X, a publicly traded partnership, operates interstate and intrastate natural gas pipelines. Y, a corporation, is a construction firm. X pays Y to build a pipeline. X later seeks reimbursement for its cost to build the pipeline from A, a refiner who contracts with X to transport gasoline.

(ii) X, as an operator of pipelines, is engaged in transportation pursuant to paragraph (c)(7)(i)(C) of this section. The reimbursement X receives from A for X’s cost to build the pipeline is qualifying income pursuant to paragraph (c)(10)(i) of this section because X receives the income to reimburse X for its costs in performing X’s transportation activity and reimbursable costs may include construction costs. In contrast, Y is not in the trade or business of performing a 7704(d)(1)(E) activity, thus income Y received from X for building the pipeline is not qualifying income to Y.

Example 7. Delivery of water. (i) X, a publicly traded partnership, owns interstate and intrastate natural gas pipelines. X built a water delivery pipeline along the existing right of way for its natural gas pipeline to deliver water to A for use in A’s fracturing activity. A uses the delivered water in fracturing to develop A’s natural gas reserve in a cost-efficient manner. X earns income for transporting natural gas in the pipelines and for delivery of water.

(ii) X’s income from transporting natural gas in its interstate and intrastate pipelines is qualifying income for purposes of section 7704(c) because transportation of natural gas is a section 7704(d)(1)(E) activity as provided in paragraph (c)(7)(i)(C) of this section.

(iii) The income X obtains from its water delivery services is not a section 7704(d)(1)(E) activity as provided in paragraph (c) of this section. However, because X’s water delivery supports A’s development of natural gas, a section 7704(d)(1)(E) activity, X’s income from water delivery services may be qualifying income for purposes of section 7704(c) if the water delivery service is an intrinsic activity as provided in paragraph (d) of this section. An activity is an intrinsic activity if the activity is specialized to support the section 7704(d)(1)(E) activity, is essential to the completion of the section 7704(d)(1)(E) activity, and requires the provision of significant services to support the section 7704(d)(1)(E) activity. Under paragraph (d)(2)(ii)(B) of this section, the provision of water for use as an injectant in a section 7704(d)(1)(E) activity is specialized to that activity only if the partnership (1) provides the water exclusively to those engaged in section 7704(d)(1)(E) activities, (2) is also in the trade or business of cleaning, recycling, or otherwise disposing of water after use in accordance with Federal, state, or local regulations concerning waste products from mining or production activities, and (3) operates these disposal services within the same geographic area as that in which it delivers water. Because X does not perform such disposal services, X’s water delivery activities are not specialized to support the section 7704(d)(1)(E) activity. Thus, X’s water delivery is not an intrinsic activity. Accordingly, X’s income from the delivery of water is not qualifying income for purposes of section 7704(c).

Example 8. Delivery of water and recovery and recycling of flowback. (i) Assume the same facts as in Example 7 of this paragraph (f), except that X also collects and treats flowback at the drilling site in accordance with state regulations as part of its water delivery services and transports the treated flowback away from the site. In connection with these services, X provides personnel to perform these services on an ongoing or frequent basis that is consistent with best industry practices. X has provided these personnel with specialized training regarding the recovery and recycling of flowback produced during the development of natural gas, and this training is of limited utility other than to perform or support the development of natural gas.

(ii) The income X obtains from its water delivery services is not a section 7704(d)(1)(E) activity as provided in paragraph (c) of this section. However, because X’s water delivery supports A’s development of natural gas, a section 7704(d)(1)(E) activity, X’s income from water delivery services may be qualifying income for purposes of section 7704(c) if the water delivery service is an intrinsic activity as provided in paragraph (d) of this section.

(iii) An activity is an intrinsic activity if the activity is specialized to support the section 7704(d)(1)(E) activity, is essential to the completion of the section 7704(d)(1)(E) activity, and requires the provision of significant services to support the section 7704(d)(1)(E) activity. Under paragraph (d)(2)(ii)(B) of this section, the provision of water for use as an injectant in a section 7704(d)(1)(E) activity is specialized to that activity only if the partnership (1) provides the water exclusively to those engaged in section 7704(d)(1)(E) activities, (2) is also in the trade or business of cleaning, recycling, or otherwise disposing of water after use in accordance with Federal, state, or local regulations concerning waste products from mining or production activities, and (3) operates these disposal services within the same geographical area as where it delivers water. X’s provision of personnel is specialized because those personnel received training regarding the recovery and recycling of flowback produced during the development of natural gas, and this training is of limited utility other than to perform or support the development of natural gas. The provision of water is also specialized because water is an injectant used to perform a section 7704(d)(1)(E) activity, and X also collects and treats flowback in accordance with state regulations as part of its water delivery services. Therefore, X meets the specialization requirement. The delivery of water is essential to support A’s development activity because the water is needed for use in fracturing to develop A’s natural gas reserve in a cost-efficient manner. Finally, the water delivery and recovery and recycling activities require significant services to support the development activity because X’s personnel provide services necessary for the partnership to perform the support activity at the development site on an ongoing or frequent basis that is consistent with best industry practices. Because X’s delivery of water and X’s collection, transport, and treatment of flowback is a specialized activity, is essential to the completion of a section 7704(d)(1)(E) activity, and requires significant services, the delivery of water and the transport and treatment of flowback is an intrinsic activity. X’s income from the delivery of water and the collection, treatment, and transport of flowback is qualifying income for purposes of section 7704(c).

(g) Effective/applicability date and transition rule. (1) In general. Except as provided in paragraph (g)(2) of this section, this section applies to income earned by a partnership in a taxable year beginning on or after January 19, 2017. Paragraph (g)(2) of this section applies during the period that ends on the last day of the partnership’s taxable year that includes January 19, 2027 (Transition Period).

(2) Income during Transition Period. A partnership may treat income from an activity as qualifying income during the Transition Period if—

(i) The partnership received a private letter ruling from the IRS holding that the income from that activity is qualifying income;

(ii) Prior to May 6, 2015, the partnership was publicly traded, engaged in the activity, and treated the activity as giving rise to qualifying income under section 7704(d)(1)(E), and that income was qualifying income under the statute as reasonably interpreted prior to May 6, 2015;

(iii) Prior to May 6, 2015, the partnership was publicly traded and had entered into a binding agreement for construction of assets to be used in such activity that would give rise to income that was qualifying income under the statute as reasonably interpreted prior to May 6, 2015; or

(iv) The partnership is publicly traded and engages in the activity after May 6, 2015 but before January 19, 2017, and the income from that activity is qualifying income under the proposed regulations (REG–132634–14) contained in the Internal Revenue Bulletin (IRB) 2015–21 (see https://www.irs.gov/pub/irs-irbs/irb15-21.pdf).

(3) Relief from technical termination. In the event of a technical termination under section 708(b)(1)(B) of a partnership that satisfies the requirements of paragraph (g)(2) of this section without regard to the technical termination, the resulting partnership will be treated as the partnership that satisfies the requirements of paragraph (g)(2) of this section for purposes of applying the Transition Period.

John Dalrymple Deputy Commissioner for Services and Enforcement.

Approved: January 12, 2017

Mark J. Mazur Assistant Secretary of the Treasury (Tax Policy).

(a) * * *

(1) [The text of the proposed amendments to § 1.871–15(a)(1) is the same as the text of § 1.871–15T(a)(1) published elsewhere in this issue of the Bulletin.]

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(g) * * *

(4) * * *

(ii) * * *

(B) [The text of the proposed amendments to § 1.871–15(g)(4)(ii)(B) is the same as the text of § 1.871–15T(g)(4)(ii)(B) published elsewhere in this issue of the Bulletin.]

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(p) * * *

(1) * * *

(ii) [The text of the proposed amendments to § 1.871–15(p)(1)(ii) is the same as the text of § 1.871–15T(p)(1)(ii) published elsewhere in this issue of the Bulletin.

(iii) [The text of the proposed amendments to § 1.871–15(p)(1)(iii) is the same as the text of § 1.871–15T(p)(1)(iii) published elsewhere in this issue of the Bulletin.]

(iv) [The text of the proposed amendments to § 1.871–15(p)(1)(iv) is the same as the text of § 1.871–15T(p)(1)(iv) published elsewhere in this issue of the Bulletin.]

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(5) [The text of the proposed amendments to § 1.871–15(p)(5) is the same as the text of § 1.871–15T(p)(5) published elsewhere in this issue of the Bulletin.]

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John Dalrymple Deputy Commissioner for Services and Enforcement.