Tax and investment planning with royalty trusts.

Royalty trusts provide investors with both potential cashflow and tax benefits. This article explains how such trusts work and their tax consequences.

Royalty trusts offer income-oriented investors the opportunity to invest in natural resources, realize cashflow from these sources and reap tax benefits afforded the natural resource industry. By combining the modified passthrough tax regime of subchapter J with full, current income distributions, these trusts can provide investors with good liquidity and diversification, along with other Federal income tax advantages. This article explains both the investment and tax attributes of royalty trusts.

Attributes

A royalty trust is a legal entity established as income-producing vehicle to purchase royalty interests (profit interests) in mature, low-risk natural resource (e.g., oil and gas) properties. (1) The trust sells beneficial interests (trust units) to investors (unit holders) to acquire capital for the trust. It then uses this capital to purchase natural resource royalty interests. It receives royalty income and distributes all of it, less management fees, to unit holders, either monthly or quarterly. A trustee, typically a bank, is appointed to provide administrative services. Royalty trusts have neither physical operations nor employees.

Because the entity functions as a simple trust in most tax years under the subchapter J rules, it is not subject to income tax and, thus, provides a tax-efficient way to distribute royalties to unit holders. Royalty trusts are neither debt nor stock, although they have some of the characteristics of equities. For example, trust units trade on organized exchanges (such as the New York Stock Exchange) and have the same type of market liquidity as stocks. Like publicly waded corporations, they register and file periodic reports with the SEC. (2) Royalty trust income is portfolio income for Sec. 469 purposes. (3)

Distributions

A royalty trust distributes all of its net cashflow to unit holders; thus, under subchapter J, it has no Federal income tax liability. Any available depreciation and depletion deductions are allocated proportionately to the income beneficiaries, sheltering a portion of the year's distributed income. Thus, the cashflow available for distribution to unit holders generally exceeds the income allocated to them. As a result, royalty trusts normally earn a high yield.

Any depletion allowance allocated to investors reduces the tax basis in their investment; thus, the cash distribution shielded by the depletion allowance is deemed a return of capital and is tax deferred. Like equities in general, when units are sold, they are generally accorded capital gain or loss treatment. However, under Sec. 1254(a)(1), the depletion allowance is recaptured as ordinary income when the unit is sold.

Risk and Return

Diversification reduces a portfolio's riskiness, a desirable outcome for most income-oriented investors, who often are risk-averse. A commodities investment offers investors an opportunity to further diversify their portfolios, because commodities normally are deemed to be a distinct asset class whose returns do not correlate with traditional stock and bond investments. Moreover, they provide a hedge against inflation. A royalty trust that derives its income from natural resources can represent a pure investment in commodities. For instance, the unit price for a royalty trust with an interest in gas wells is tied directly to the underlying price of gas. As the price of gas increases, the royalty trust's value would also be expected to increase. At the same time, the investor avoids the exploration risk present with integrated oil companies.

A royalty trust is a claim on finite resources, albeit long-lived ones whose lives may last for two or three decades or more. As the resources are depleted, distributions will eventually fall to zero. In essence, distributions are, in part, a return of an investor's original investment, much like an annuity whose payout is partly a return of capital and partly a return on capital. Unlike dividend payments, the level of which is normally stable from year to year, royalty trust distributions are not guaranteed--they will vary depending on the price of the underlying natural resource. For example, Exhibit 1 below shows annual distributions of a large oil royalty trust, BP Prudhoe Bay Royalty Trust (BPT), since its formation. It illustrates the considerable annual fluctuation in distributions, which have varied from $0.57-$4.05/unit. At the beginning of 1999, the price of a barrel of crude oil was $8.64: for that year, BPT distributed only $0.57. In contrast, at the beginning of 2004, a barrel of oil cost $30.87; for that year, the trust paid $3.82. (4)

Unfortunately, there is no readily available index that tracks royalty trusts' aggregate historical returns. However, current track records for several publicly traded royalty trusts show that such trusts generally have excellent long-run returns (such as San Juan Basin Royalty Trust, which owns interests in gas wells located in the San Juan basin area of northern New Mexico).

Predicting Future Returns

Estimating future rates of return for any speculative investment invariably involves uncertainty, because of the difficulty in assigning accurate numbers to the variables. However, for royalty trusts, these estimations arguably involve less guesswork than for traditional equities, because it is often easier to assign amounts to the variables that determine the returns. The primary variables are the (1) current yield, (2) remaining reserve life (derived from the remaining reserve amount) and (3) future price levels of the natural resource.

Current yield can be obtained from any number of financial websites. (5) Reserve information is required on Form 10-K, Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. (6) While future natural resource prices are hard to estimate, historical price trends may indicate future ones. Exhibit 2 at right provides estimated rates of return for different distribution yields, remaining lives and unit prices. It shows that the greater the remaining life and the higher the initial yield, the greater the realized overall rate of return. Moreover, an increase in unit price generally translates into a significant increase in the rate of return. Exhibit 2 also demonstrates that a royalty mast can need 15 or more years of remaining life (given the assumed yield and unit price increases) to generate a respectable return. However, when the remaining life extends beyond 30 years, the fact that the royalty trust is approaching termination has very little adverse affect on the rate of return.

Why Use a Royalty Trust?

Generally, when a corporation carves out royalty interests in productive natural resources to create a royalty trust, it either distributes the mast units to its shareholders as a property dividend or sells them to (existing and new) investors. (7) When the corporation contributes royalty interests to a trust, then distributes trust units to its shareholders, the Service recasts the transaction as a distribution by the corporation of the royalty interests to the shareholders, followed by an immediate transfer of the property interests by the unit holders to the trust. (8)

Raising Capital

Corporations are willing to share the tax benefits from proven mineral properties for two reasons. First, liquidating properties--by either moving them to a royalty trust or selling unit interests--tends to provide more capital than would conventional financing. This technique provides funds for alternative projects that, while riskier, offer the prospect for higher growth. Thus, the corporation can currently receive operating capital for further explorations. Also, under Regs. Sec. 1.1254-1(b)(3)(ii), a transfer of overriding royalties to a shareholder trust does not require recapture of previously deducted intangible drilling costs (IDC), as is usually the case under Sec. 1254, because the transfer of an overriding interest is not a disposition of an operating interest. (9)

Avoiding AMT

Second, not all C corporations can take advantage of the tax benefits available to

natural resource investors. Natural resource corporations tend to be subject to the alternative minimum tax (AMT) due to their exploration expenses. The IDC for the oil and gas industry, for example, is deductible currently for regular tax, but must be capitalized and amortized over 10 years for AMT purposes, under Sec. 57(a)(2). This can cause corporations in this industry additional AMT problems.

AMT issues may also arise under Sec. 57(a)(1), because percentage depletion (with some exceptions) in excess of the property's basis is not allowed for AMT purposes. Further, credits such as the enhanced oil recovery credit do not reduce AMT. Consequently, the corporation may find it prudent to sell off these tax attributes, by spinning off proven natural resource properties into a royalty trust and selling trust units.

Taxation of Royalty Trusts

Classification

A royalty trust is a grantor mast and the unit holders are the grantors, regardless of how they acquire units. (10) It generally holds "nonworking" (i.e., nonoperating) royalty interests that are property interests under state law. (11) The trustee, usually a party independent from the entity owning the operating interest, merely collects the royalties, pays associated costs and distributes the net proceeds to the unit holders. Because the trustee does not have the power to engage in any other business or vary the unit holders' investments, the trust is deemed to be owned by the unit holders under subchapter J rules. (12) Thus, because the unit holders are regarded as both the grantors and the income beneficiaries, a royalty mast is a grantor mast.

Flowthrough of Items

Under Sec. 671, grantors or others deemed the owners of a grantor trust report their proportionate shares of all income and deduction items on their personal returns. The trust files a "blank" Form 1041, U.S. Fiduciary Income Tax Return, reporting identification of the grantors only. The grantors report the entity's income, deductions, credits and AMT items in proportion to their holdings, as though they had generated them directly.

Sec. 672 is definitional; Secs. 673-679 identify specific situations that cause the grantor or other party to be mated as the "owner" of all or a portion of a trust. The trust income is taxed to the grantor as the trust's owner if the grantor can:

* Revoke the mast or return the corpus to the grantor (for revocable trusts under Sec. 676);

* Distribute income to or for the grantor's benefit (for income benefit mists under Sec. 677);

* Change the beneficiaries' interests in the trust under Sec. 674; or

* Benefit by exercising administrative rights under Sec. 675.

It is important to identify the "grantor" and determine whether the grantor is the "owner." If a trust unit is purchased outright by an investor, that person is treated as a grantor. As previously stated, if a trust is created by a corporate spinoff, the shareholders are treated as the grantors.

Sec. 671 and its regulations illustrate how each grantor is taxed. Under Kegs. Sec. 1.671-2(c), all items of income, deduction and credit allocated to unit holders are treated as if they were received directly, rather than from an entity. Thus, the royalty mast does not send each unit holder a Schedule K-1, Beneficiary's Share of Income, Deductions, Credits, etc., as a typical mast would do. Rather, unit holders are treated as owners of an undivided fractional interest in the mast, usually represented by the units owned. Their pro-rata share of each item of income, deduction and credit is normally allocated to them under Regs. Sec. 1.671-3(a)(3) based on this undivided interest. This implies that the unit holders of undivided mast interests own their proportionate interests in each of the mast's assets for Federal income tax purposes. (13) The consequences are very similar to those under partnership tax law.

Typically, a unit holder receives allocations of royalty income, administration expenses, severance taxes and depletion. These items are reported on Schedule E, Supplemental Income and Loss, for individuals. The royalty interests may also generate credits, such as the Sec. 29 credit for producing fuel from a nonconventional source. These are reported in the "Taxes and Credits" section of Form 1040. Taxpayers must attach a separate schedule computing the credit, as there is no separate form. This credit is not a component of the general business credit.

Depletion

Depletion is similar to the depreciation deduction allowed for tangible assets. It is a method of recovering the costs of natural resources and is allowed under Sec. 611. As the natural resource is removed, a portion of its original cost is deducted. Depletion deductions recognize that a natural resource is a "wasting" asset; as depletion deductions are taken, the basis in the asset decreases. As a result, a subsequent sale of the property for more than its depleted basis results in a taxable gain.

Under Regs. Sec. 1.611-1(b), the natural resource's economic owner takes the depletion deduction. Given that the unit holders each own a proportionate share of each asset in the royalty trust, they qualify as economic owners for depletion purposes. (14) In most cases, the entire cost of the unit holder's investment is the basis for depletion. Each royalty interest owned by the trust is deemed an economic interest and constitutes a single, depletable property.

Two types of depletion are available--cost and percentage (also called statutory depletion). Depletion is calculated using both methods; the one that produces the greater deduction should be used. (15) For interests acquired before October 1990, cost depletion is permitted only for proven properties. (16)

Cost depletion: Cost depletion recovers the adjusted basis of a natural resource. Sec. 1011(a) basis is divided by the estimated recoverable units of the resource to develop depletion per unit. According to Regs. Sec. 1.6112(a), cost is recovered through depletion based on the units sold during the year. If the recoverable units are determined during the year to be more or less than the original estimate, the depletion per unit is recalculated; there is no adjustment to prior-year deductions, under Sec. 611(a).

When the full cost has been recovered, no further cost depletion is allowed. Cost depletion is similar to depreciating a tangible asset down to a zero basis. Because the trustee does not know the purchase price of each unit holder's interests, the mast cannot compute cost depletion for the investors. Each investor computes his or her own deduction. The mast will generally provide cost depletion factors for each investor to apply his or her remaining cost basis.

Example 1: J purchased 1,000 units of ACE Royalty Trust for $22,000. Cost depletion taken in prior years was $6,000. ACE provides a cost-depletion factor of 7%. J's cost depletion is computed as follows:

Cost of units             $22,000
Less prior depletion      (6,000)
Current basis              16,000
Depletion factor           x 0.07
Cost depletion for year    $1,120

Percentage depletion: Percentage depletion is based on a specified percentage of gross income from a natural resource, rather than on its cost. The percentage varies depending on the type of natural resource being recovered. This type of depletion is often referred to as "statutory depletion," because the percentages are defined in Sec. 613. For example, oil and gas properties are often entitled to a 15% depletion allowance under Sec. 613(b)(2). Percentage depletion often produces deductions in excess of the property's basis, because it is computed as a percentage of the property's gross income. Percentage depletion may be taken even after the total cost (basis) has been recovered by prior depletion deductions. However, under Sec. 613(a),it cannot be in excess of 50% (100% for oil and gas properties) of the taxable income from the property.

Example 2: S purchased 1,000 units of ACE Royalty Trust for $14,000. In previous years, S claimed $9,000 for depletion. In the current year, ACE has $6 income per unit and $3.50 administrative and other expenses per unit. The cost-depletion factor is 7%. S's percentage depletion is computed as follows:

Gross income                    $6,000 (1,000 units x $6.00)
Less expenses                   (3,500) (1,000 units x $3.50)
Income before depletion         2,500
Depletion percentage            x15%
Percentage depletion for year   $375

S's cost depletion is computed as follows:

Cost of units              $14,000
Less: prior depletion      (9,000)
Current basis                5,000
Depletion factor            x 0.07
Cost depletion for year       $350

Because percentage depletion exceeds cost depletion, S will take the former for tax purposes.

In the case of oil and gas wells, Sec. 613A potentially limits the availability of percentage depletion; it is allowed only for regulated natural gas, natural gas sold under a fixed contract, natural gas from geo-pressured brine and independent domestic producers, and to royalty owners whose production does not exceed certain levels. These limits may apply to the mast unit holders, as well.

See. 29 Credit

A credit is allowed under Sec. 29 against regular income tax for the production of fuel from a nonconventional source. This credit may offset tax generated from all types of income, but it cannot be applied in computing AMT. The annual credit is based on the amount of the barrel-of-oil equivalent of qualified fuels produced. The following fuels are eligible for the credit:

* Oil produced from shale or tar sand;

* Gas produced from geo-pressured brine, Devonian shale, coal seams, a tight formation or biomass; and

* Liquid, gaseous or solid fuels produced from coal.

The credit is designed to encourage the development of certain natural resources, by decreasing their production cost relative to the price of imported oil. The production of these natural resources generally involves new technology; the credit provides a subsidy to encourage development of this technology to such a state that it can be competitive with conventional fuels.

Under Sec. 29(f)(1), natural resources production must be from facilities placed into service, or from wells drilled, after 1979 and before 1993, and sold before 2003. However, for facilities producing fuel gas from biomass or coal, the 1993 date is extended to July 1, 1998; if the facility was originally placed in service after 1992, the final sales date is extended to the end of 2007, under Sec. 29(g).

The Sec. 29 credit is allowed in the year in which the unit holder receives the related income distribution, not the year in which the natural resource was sold, nor the year the trust received the royalty. This rule applies to both cash- and accrual-basis taxpayers. (17) The credit usable in any tax year cannot exceed the regular tax liability, reduced by the foreign tax credit and certain nonrefundable credits. It also cannot reduce the regular tax liability below the AMT tentative minimum tax liability. Any credit that cannot be used because of the AMT limit increases the AMT credit. The AMT credit is carried forward indefinitely until it can be used against the regular tax liability. Other than the AMT limit provision, there are no possibilities for carrying back or forward any Sec. 29 credit not currently taken.

Basis Adjustment and Sale

Depletion deductions reduce a unit holder's basis in a royalty mist investment. Each unit holder is responsible for keeping track of the basis of each unit. When a unit is ultimately sold, the gain or loss recognized is the difference between the amount realized and the unit holder's original basis in the investment. If the units were held longer than one year, the long-term capital gain rate applies. However, the difference between original basis and adjusted basis at the sale date is recaptured as ordinary income under Sec. 1254. (Depletion recapture is similar to depreciation recapture.)

If the investor has made multiple acquisitions of units and disposes of fewer than all of them, he or she must identify the units sold to determine their basis. While the regulations do not address the methods available for identifying royalty trust units, Regs. Sec. 1.1012-1 indicates that specific identification or a FIFO method may be used for stock sales. Presumably, these two methods would also be available for royalty trust units.

Taxable or Retirement Account?

There do not appear to be any publicly available mutual funds specifically dedicated to royalty masts. Thus, an interest may be acquired only through a brokerage account. While some investors will use a self-directed brokerage account in a retirement account (such as a Sec. 401(k) plan or 403(b) plan), traditional IRA or Roth IRA, most will not. It is more common for investors to have a brokerage account only in a taxable account.

If an investor has a brokerage account in both a taxable account and a retirement account, he or she must decide which to use for the royalty trust. Generally, as long as the investment is intended to meet future retirement needs and retirement account contribution limits are of no concern, the royalty mast units should be placed in a retirement account to shelter the flow of current income. If, on the other hand, the investment is intended to meet short-term goals (particularly the need for immediate retirement income), trust units should be held in a taxable account.

If an investor has more funds earmarked for retirement than retirement contribution limits allow, he or she should first place the least tax-efficient assets in a retirement account. Generally, fixed-income assets are the least tax-efficient, because all their earnings are immediately taxed as ordinary income. Equities traded with sufficient frequency for capital gains to be treated as short-term (taxed at ordinary income rates) would also be deemed relatively tax-inefficient. Equities held for a long-term period are relatively tax-efficient (including those that pay a high dividend rate, as long as the dividends qualify for the long-term capital gain rate).

Royalty trusts, in terms of tax efficiency, fall roughly between tax-inefficient fixed income investments and tax-efficient equities held for more than 12 months. Almost all of the return from royalty trusts would be expected to be generated from cash distributions, a portion of which is tax deferred, but ultimately taxed at ordinary income rates because of Sec. 1254 recapture. However, the current tax-sheltering aspects of depletion deductions are effectively lost if trust units are placed in a qualified retirement account. Further, these aspects must be balanced against the unit holder's risk tolerance and his or her need for current cash. Most individuals likely now hold royalty trust interests in taxable accounts.

Conclusion

A royalty trust offers a combination of investment and tax incentives. For the income-oriented investor who can withstand valuation fluctuations, the device can be a good source of cash-flow, and a means of enjoying the tax benefits afforded to natural resources. The attributes of the royalty trust make it an attractive investment device, especially for individuals with modest portfolios and little access to direct investments in natural resources.

(1) This definition is consistent with the Securities and Exchange Commission (SEC) definition of royalty trusts; see SEC Staff Accounting Bulletin, Topic 12: Oil and Gas Producing Activities at 12E, "Financial Statements of Royalty Trust," available at www.sec.gov/interps/account/sabcodet12.htm#12e.

(2) According to the SEC, any company with more than $10 million in assets whose securities are held by more than 500 owners must file annual and other periodic reports. These reports are available to the public via the SEC's Electronic Data Gathering, Analysis and Retrieval (EDGAR) system, at www.sec.gov/edgar/searchedgar/webusers.htm.

(3) See Sec. 469(e)(1)(A)(i)(I). This discussion is limited to royalty trusts based in the U.S. and subject to U.S. tax law. It does not address Canadian-based royalty trusts, which sometimes are traded on U.S. exchanges.

(4) See the Illinois Oil and Gas Association's website at www.ioga.com for a history of crude oil prices.

(5) See, e.g., http://finance.yahoo.com for yield data.

(6) 17 CFR [section]229.801(b) (Securities Act industry guides, Guide 2: Disclosure of Oil and Gas Operations).

(7) Industry terminology for carving out royalty interests is "spinning off" the interests. This is not, technically, a spinoff D reorganization, however; see Sec. 368(a)(1)(D). A shareholder's basis in a property dividend is determined under Sec. 301(b)(1).

(8) See Rev. Rul. 72-137, 1972-1 CB 101, and IRS Letter Ruling 8223015 (2/26/82).

(9) Southland Royalty Company, 22 Cl. Ct. 525 (1991).

(10) See Rev. Rul. 72-137, note 8 supra, and IRS Letter Ruling 8223015, note 8 supra.

(11) For examples of state law treatment, see Reese P. Fullerton v. Lucille C. Kaune, 382 P2d 529 (NM 1963); Neb. Rev. Stat. [section]77-103(4); Mesa Verde Co. v. The Montezuma Cty. Bd. of Equalization, 898 P2d 1 (CO 1995) and CO Rev. Star. [section]39-1-102(14)(b).

(12) See Regs. Sec. 301.7701-4(c); IRS Letter Ruling 8223015, note 8 supra; and Rev. Ruls. 78-149, 1978-1 CB 448 and 75-192, 1975-1 CB 184.

(13) See Prop. Regs. Sec. 1.671-2(f) and Rev. Rul. 85-13, 1985-1 CB 184.

(14) See IRS Letter Ruling 8411017 (12/7/83).

(15) See Regs. Sec. 1.611-1(a)(1) and IRS Letter Ruling 8411017, note 14 supra.

(16) See pre-Revenue Reconciliation Act of 1990 (RRA '90) Sec. 613A(c)(9) and (10). RRA '90 Section 11521 repealed the cost-depletion requirement on the transferred proven-property rule, prospectively only. Proven properties transferred before Oct. 12, 1990, may not claim percentage depletion.

(17) See Rev. Proc. 2004-27, IRB 2004-17, 831

Richard B. Toolson, Ph.D., CPA Professor Department of Accounting Washington State University Pullman, WA

Debra L. Sanders, Ph.D., CPA Professor Department of Accounting Washington State University Pullman, WA

William A. Raabe, Ph.D., CPA Tax Faculty Fisher College of Business Ohio State University Columbus, OH