Thursday, October 31, 2019
An interesting question was posed to me at a recent tax seminar. The question was whether director fees are subject to self-employment tax. That question comes up because sometimes farmers, ranchers and others receive income for serving as a director of a farming or ranching business, an agricultural cooperative, an ag lender or other organization.
Whether a director fee is subject to self-employment tax turns on whether the fee constitutes employee wages. Making that determination turns on the facts and circumstances of the particular situation.
Director fees and self-employment tax – it’s the topic of today’s post.
Self-Employment Tax Basics
A self-employed individual is one who has net earnings from self-employment as defined by I.R.C. §1402(a). “Net earnings from self-employment” means gross income derived from a trade or business that the taxpayer conducts (less associated deductions). Id. But, a “trade or business” for self-employment tax purposes does not include “the performance of services by an individual as an employee.” I.R.C. §1402(c)(2).
A corporate director, under the right set of facts, is not a corporate employee. Treas. Reg. §31.3121(d)-1(b) specifies that, “Generally, an officer of a corporation is an employee of the corporation. However, an officer of a corporation who as such does not perform any services or performs only minor services and who neither receives nor is entitled to receive, directly or indirectly, any remuneration is considered not to be an employee of the corporation. A director of a corporation in his capacity as such is not an employee of the corporation.”
On the self-employment tax issue, the IRS ruled in 1972, that director fees are self-employment income subject to self-employment tax. Rev. Rul. 72-86, 1972-1 CB 273. That is certainly the case if a “director” performs no services for the corporation. But, what if some services are provided? When does a “director” cross the line and grade over into “employee” status with payments received constituting wages? If the fees constitute “wages” they aren’t subject to self-employment tax and there could be other implications.
The Blodgett case
In Blodgett v. Comr., T.C. Memo. 2012-298, the petitioner served on a local bank board. The board operated independently and represented members of the community that owned the bank. The board supervised bank management but did not participate in daily bank operations. The bank provided liability coverage, life and disability insurance and retirement benefits, but not health insurance to the board members. The petitioner was also vested in the bank’s retirement plan for board members. He put in less than five hours a week on board member business and did not hold himself out as a contractor and did not claim any tax deductions for business expenses because the bank paid all expenses. The bank issued him a Form 1099-MISC, Miscellaneous Income, reporting "nonemployee compensation" of $26,750 for his services. He reported the amount on line 21 of his return as “other income” not subject to self-employment tax. The IRS disagreed, asserting that the income was attributable to work the petitioner performed as an independent contractor and that self-employment tax was owed.
The Tax Court agreed with the IRS and analyzed the facts based on a seven-factor test. Those factors, set forth in Weber v. Comr., 103 T.C. 378 (1994), are: (1) extent of control maintained by the bank; (2) responsibility for providing work facilities; (3) the opportunity for the trustee to receive a profit or loss; (4) the ability of the bank to fire the trustee; (5) the trustee duties as part of the bank’s regular business activities; (6) the permanency of the bank-trustee relationship; and (7) the intent of the bank-trustee relationship.
Here's how the factors shook out in Blodgett:
Factors favoring employee status:
- The bank provided the trustees with meeting rooms, office supplies, and other items necessary to fulfill their duties.
- The trustees were paid for attending board meetings and did not have additional opportunities for profit or loss.
- The petitioner had been reelected to his position for more than 10 consecutive three-year terms, but bank management was appointed for one-year terms.
Factors favoring nonemployee status:
- The board of trustees operated independently from the bank’s management and were not subject to any meaningful control by the bank.
- Only corporate members could terminate the trustees, and then only on a limited basis including by a vote of the members.
- The trustees’ duties were primarily related to oversight with no involvement in daily bank operations.
- Evidence showed that the bank had no intent to create and employer-employee relationship with the trustees and issued Forms 1099-Misc. instead of Forms W-2 to all of the trustees.
The court didn’t simply stack up the factors and see whether a majority of them favored employee or nonemployee status. Instead, the court placed the most weight on how much control the bank exercised over the trustees and determined that the trustees were not employees and that self-employment tax was owed.
The Burbach Case
In Burbach v. Comr., T.C. Memo. 2019-17, the petitioner was an engineer whose LLC business involved working with towns to determine the need for a public pool. If it was determined that a pool had merit, the petitioner would plan and market the pool and organize fundraising for the construction of the pool. Ultimately, he changed his business form from an LLC to two corporations – one to hold the operating assets of the business and another corporation to hold real estate. With help from his tax advisor, the petitioner established a self-employed pension plan. He funded the plan by taking “director fees” out of the operating entity which he then deposited into his personal checking account with subsequent transfers to his pension account. He reported the director fees on Schedule C and claimed an offsetting deduction for the contributions to his self-employed retirement plan.
The facts got tangled with respect to late-filed corporate returns and ultimately it was determined that the pension plan needed to be an employer-sponsored plan run through the operating entity because it had employees and also because all the compensation on which plan contributions were based was W-2 compensation that the corporation paid to the petitioner as an employee. The plan was corrected retroactively with the operating entity as the plan sponsor including all eligible employees in the plan and including the amounts the petitioner received as director fees for plan purposes.
The parties settled on the plan qualification issues, but the IRS claimed that the director fees the petitioner received were wages as remuneration for employee services. As wages, the IRS argued, the petitioner couldn’t claim I.R.C. §404 pension plan deductions because he had no self-employment income.
The Tax Court agreed with the IRS for the following reasons:
- The petitioner was the operating entity’s sole shareholder and was involved hands-on in the company’s daily affairs.
- While the petitioner was the operating entity’s only director, there was no evidence that he provided any director services. Instead, the services provided involved daily decisions concerning engineering, project management and marketing.
- The petitioner had represented to the IRS when he and the operating entity applied for a compliance statement for the pension plan that he was providing services that were essentially employee services.
Consequently, the petitioner had no earnings from self-employment and I.R.C. §404(a)(8) barred him from claiming any deductions for contributions he had made to his Keogh-type pension plan for the tax years at issue. Instead, he was an “employee” within the meaning of I.R.C. §401(c)(1) and the operating entity was his “employer” under I.R.C. §401(c)(4) by virtue of I.R.C. §404(a)(8).
Note that the outcome in Burbach was different that the typical outcome with respect to directors’ fees. While it’s a facts and circumstances determination, most often those facts indicate that directors’ fees are self-employment income. Had that been the case in Burbach, the petitioner, as a corporate director, could have established a Keogh plan based on those fees. See, e.g., I.R.C. §3121(d)(1); Treas. Reg. §31.3121(d)-1(b). However, the petitioner provided more than minor services and was classified as an employee whose director fees were classified as wages.
It’s not uncommon in rural areas for farmers, ranchers and others to serve on various corporate boards for which compensation is received. It’s important to properly report the director fee income on the return. That will turn on the classification of the relationship of the taxpayer to the entity involved. Facts and circumstances of each situation are critical. If the taxpayer is deemed to be an independent contractor with self-employment income, perhaps there are associated costs that can be deducted to help offset the income and self-employment tax. Likewise, it may be possible to establish a pension plan. But the facts must support the classification desired.
Tuesday, October 29, 2019
One of the new taxes created under Obamacare is a 3.8 percent tax on passive sources of income of certain individuals. It’s called the “net investment income tax” and it took effect in January of 2013. Its purpose was to raise about half of the revenue needed for Obamacare. It’s a complex tax that can surprise an unsuspecting taxpayer – particularly one that has a one-time increase in investment income (such as stock). But it can also apply to other sources of “passive” income, such as income that is triggered upon the sale of farmland.
But are farmland sales always subject to the additional 3.8 percent NIIT? Are there situations were the sale won’t be subject to the NIIT? These questions are the topic of today’s post.
The NIIT is 3.8% of the lesser of (1) net investment income (NII); or (2) the excess of modified adjusted gross income (MAGI) over the threshold amount ($250,000 for joint filers or surviving spouses, $125,000 for a married individual filing a separate return, and $200,000 in any other case). I.R.C. §1411. The threshold amount is not indexed for inflation. For this purpose, MAGI is defined in Treas. Reg. §1.1411-2(c)(2). For an estate or trust, the NIIT is 3.8% of the lesser of (1) undistributed NII; or (2) the excess of AGI (as defined in I.R.C. §67(e)) over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins ($12,750 for 2019). I.R.C. §1411(a)(2).
What is NII? For purposes of the NIIT, net investment income (NII) is gross income from interest, dividends, annuities, royalties, and rents, unless derived in the ordinary course of a trade or business to which the NII tax doesn't apply. I.R.C. §1411(c)(1)(A)(i). If the taxpayer either owns or is engaged in a trade or business directly or indirectly through a disregarded entity, the determination of character of income for NIIT purposes is made at the individual level. Treas. Reg. §1.1411-4(b)(1). If the income, gain or loss traces to an investment of working capital, it is subject to the NIIT. I.R.C. §1411(c)(3). Also, the NIIT applies to business income if the trade or business at issue is a passive activity. I.R.C. §1411(c)(2)(A). But, if income is subject to self-employment tax, it’s not NII subject to the NIIT. I.R.C. §1411(c)(6).
Sale of Farmland and the NIIT
Capital gain income can trigger the application of the NIIT. However, if the capital gain is attributable to the sale of a capital asset that is used in a trade or business in which the taxpayer materially participates, the NIIT does not apply. For purposes of the NIIT, material participation is determined in accordance with the passive loss rules of I.R.C. §469.
If an active farmer sells a tract of land from their farming operation, the capital gain recognized on the sale is not subject to the NIIT. However, whether the NIIT applies to the sale of farmland by a retired farmer or a surviving spouse is not so easy to determine. There are two approaches to determining whether the NIIT applies to such sales – the I.R.C. §469(f)(3) approach and the I.R.C. §469 approach
I.R.C. §469(h)(3) approach. I.R.C. §469(h)(3) provides that “a taxpayer shall be treated as materially participating in any farming activity for a taxable year if paragraph (4) or (5) of I.R.C. §2032A(b) would cause the requirements of I.R.C. §2032A(b)(1)(C)(ii) to be met with respect to real property used in such activity if such taxpayer had died during the taxable year.” The requirements of I.R.C. §2032A(b)(1)(C)(ii) are met if the decedent or a member of the decedent’s family materially participated in the farming activity five or more years during the eight years preceding the decedent’s death. In applying the five-out-of-eight-year rule, the taxpayer may disregard periods in which the decedent was retired or disabled. I.R.C. §2032A(b)(4). If the five-out-of-eight year rule is met with regard to a deceased taxpayer, it is deemed to be met with regard to the taxpayer’s surviving spouse, provided that the surviving spouse actively manages the farming activity when the spouse is not retired or disabled. I.R.C. §2032A(b)(5).
To summarize, a retired farmer is considered to be materially participating in a farming activity if the retired farmer is continually receiving social security benefits or is disabled; and materially participated in the farming activity for at least five of the last eight years immediately preceding the earlier of death, disability, or retirement (defined as receipt of social security benefits).
The five-out-of-eight-year test, once satisfied by a farmer, is deemed to be satisfied by the farmer’s surviving spouse if the surviving spouse is receiving social security. Until the time at which the surviving spouse begins to receive social security benefits, the surviving spouse must only actively participate in the farming operation to meet the material participation test.
“Normal” I.R.C. §469 approach. A counter argument is that I.R.C. §469(h)(3) concerns the recharacterization of a “farming activity,” but not the recharacterization of a rental activity. Thus, if a retired farmer is no longer farming but is engaged in a rental activity, §469(h)(3) does not apply and the normal material participation tests under §469 apply.
What are the material participation tests of I.R.C. §469? As set forth in Treas. Reg. §1.469-5T, they are as follows:
(1) The individual participates in the activity for more than 500 hours during such year;
(2) The individual's participation in the activity for the taxable year constitutes substantially all of the participation in such activity of all individuals (including individuals who are not owners of interests in the activity) for such year;
(3) The individual participates in the activity for more than 100 hours during the taxable year, and such individual's participation in the activity for the taxable year is not less than the participation in the activity of any other individual (including individuals who are not owners of interests in the activity) for such year;
(4) The activity is a significant participation activity (within the meaning of paragraph (c) of this section) for the taxable year, and the individual's aggregate participation in all significant participation activities during such year exceeds 500 hours;
(5) The individual materially participated in the activity (determined without regard to this paragraph (a)(5)) for any five taxable years (whether or not consecutive) during the ten taxable years that immediately precede the taxable year;
(6) The activity is a personal service activity (within the meaning of paragraph (d) of this section), and the individual materially participated in the activity for any three taxable years (whether or not consecutive) preceding the taxable year; or
(7) Based on all of the facts and circumstances (taking into account the rules in paragraph (b) of this section), the individual participates in the activity on a regular, continuous, and substantial basis during such year.
The above tests don’t apply to a limited partner in a limited partnership, and only one of the tests is likely to have any potential application in the context of a retired farmer to determine whether the taxpayer materially participated in the farming activity – the test of material participation for any five years during the ten years preceding the sale of the farmland.
Clearly, the “normal” approach would cause more transactions to be subject to NIIT. It’s also the approach that the IRS uses, and it is likely the correct approach.
Sale of land held in trust. When farmland that has been held in trust is sold, the IRS position is that only the trustee of the trust can satisfy the material participation tests of §469. This is an important point because of the significant amount of farmland that is held in trust, particularly after the death of the first spouse, and for other estate and business planning reasons. However, the IRS position has been rejected by the one federal district court that has ruled on the issue. Mattie K. Carter Trust v. U.S., 256 F.Supp.2d 536 (N.D. Tex. 2003). The IRS did not appeal the court’s opinion, but continued to assert in in litigation in other areas of the country. In a case from Michigan in 2014, the U.S. Tax Court in a full tax court opinion, rejected the IRS’s position. Frank Aragona Trust v. Comm’r, 142 T.C. 165 (2014). The Tax Court held that the conduct of the trustees acting in the capacity of trustees counts toward the material participation test as well as the conduct of the trustees as employees. The Tax Court also implied that the conduct of non-trustee employees would count toward the material participation test. The court’s opinion makes it less likely that the NIIT will apply upon trust sales of farmland where an actual farming business is being conducted.
Obamacare brought with it numerous additional taxes. One of those, the NIIT, applies to passive income of taxpayer’s with income above a certain threshold. The NIIT can easily be triggered upon sale of particular assets that have been held for investment or other purposes, including farmland. Some planning may be required to avoid its impact.
Friday, October 25, 2019
Water is an important natural resource to agriculture. In some parts of the country it is more plentiful than it is in other areas. That relative scarcity has led the legal system to develop, over time, different approaches for the allocation of water rights. Particularly in the western two-thirds of the U.S. where water is most scarce, water rights are regulated by at the state level.
The state regulation of water rights can have a significant impact on agricultural activities and land values. But, just how far can a state go in regulating such rights? How solid is the water right of a farmer or rancher? It’s a big issue that is looming large in Kansas at the present time.
The state regulation of water rights – it’s the topic of today’s post.
The Prior Appropriation System
Most of the United States west of the 100th Meridian (a longitude line connecting the North and South Poles that runs through Cozad, Nebraska, Dodge City, Kansas that also forms the eastern border of the Texas panhandle with Oklahoma) utilizes the prior appropriation system for purposes of allocating water. See, e.g., In re Water Rights of Deschutes River and Tributaries, 134 Ore. 623, 286 P. 1049 (1930).
The prior appropriation system is based on a recognition that water is relatively scarce, and establishes rights to water based on when water is first put to a beneficial use. The doctrine grants to the individual first placing available water to a beneficial use, the right to continue to use the water against subsequent claimants. Thus, the doctrine is referred to as a “first in time, first in right” system of water allocation. The oldest water right on a stream is supplied with the available water to the point at which its state-granted right is met, and then the next oldest right is supplied with the available water and so on until the available supply is exhausted. In order for a particular landowner to determine whether such person has a prior right as against another person, it is necessary to trace back to the date at which a landowner's predecessor in interest first put water to a beneficial use. The senior appropriator, in the event of dry conditions, has the right to use as much water as desired up to the established right of the claimant to the exclusion of all junior appropriators.
The right to divert and make consumptive use of water from a watercourse under the prior appropriation system is typically acquired by making a claim, under applicable procedure, and by diverting the water to beneficial use. The “beneficial use” concept is basic; a non-useful appropriation is of no effect. What constitutes a beneficial use depends upon the facts of each particular case. A prior appropriation water right is typically administered by a state agency that certifies via the issuance of a permit that a water right has been acquired dating from a particular time and tying it to a particular diversion point.
As applied to groundwater, the prior appropriation doctrine holds that the person who first puts groundwater to a beneficial use has a priority right over other persons subsequently desiring the same water. This doctrine is applied in many western states that also follow the prior appropriation doctrine with respect to surface water.
A prior appropriation water right is typically administered by a state agency that certifies via the issuance of a permit that a water right has been acquired dating from a particular time and tying it to a particular diversion point. Accordingly, such a state administrative process basically confirms the application of the prior appropriation system. But, can a state do more than simply validate a prior appropriation right and establish a regulatory framework for protecting those rights? Can a state modify the regulatory system in a manner that diminishes existing water rights without triggering liability to the existing right holders or owing them compensation? This last point is being tested in Kansas, a state that utilizes the prior appropriation doctrine, at the present time.
A case in western Kansas is presently testing the limits of how far a state regulatory agency can go in regulating existing water rights. Just recently the local county trial court issued its opinion in Friesen v. Barfield, No. 2018 CV 10 (Gove County, KS Dist. Ct. Oct. 15, 2019). The case involved the application of a Kansas law that took effect in 2012, that modified existing water rights.
Under the facts of the case, Kansas Ground Water Management District (GMD) 4 was the first GMD to implement a Local Enhanced Management Area (LEMA) that Kansas law authorized beginning in 2012. A LEMA allows GMD’s to voluntarily implement water conservation practices. After great success with the first LEMA, GMD 4 proposed a district-wide LEMA. The GMD held many public meetings over 2015 and 2016. The GMD Board approved the final LEMA plan and submitted it to the Chief Engineer, Division of Water Resources (CE). The CE approved the LEMA Plan on June 27, 2017, and an official public notice and comment period was opened. After the required two public hearings, the CE found that the LEMA plan was satisfactorily addressed the water conservation issues within GMD 4, and approved the plan. On April 13, 2018, the CE issued the Order of Designation creating the GMD District-Wide LEMA.
The plaintiffs, irrigators and voting members of the GMD, sued to stop the implementation of the LEMA on the basis that it violated vested water rights, was arbitrary and capricious, and unconstitutional. The local trial court disagreed and upheld the district-wide LEMA. The plaintiffs claimed that the water conservation restrictions contained in the proposal were a “collateral attack” on perfected water rights that the CE could not alter. The trial court disagreed, concluding that the groundwater permits did not guarantee any set amount of water. In addition, the trial court noted that the district-wide LEMA was not a permanent reduction in water appropriation but contemplated revisiting the matter in the future. Thus, the trial court concluded that so long as the LEMA is in place and the reduction in pumping is within state law limits, the CE had the discretion to approve the district-wide LEMA.
The plaintiffs also claimed that state law did not provide a definitive guide to the CE and did not protect against arbitrary action, unfairness, or favoritism. The trial court disagreed, noting that state law establishes six prerequisites for a LEMA, five of which must occur within the LEMA area - including decline of the water source. In addition, the trial court noted that the LEMA was additionally reviewable by the state Ag Secretary and subject to judicial review. The trial court also noted that the GMD is elected in a democratic process.
On the plaintiffs’ constitutional equal protection claim, the trial court determined that the LEMA, while sorting irrigators into different classes, did not violate equal protection because such sorting was rationally related to the LEMA's purposes of conserving water resources. On the plaintiffs' claim that the state law governing a LEMA cannot adversely affect vested water rights, the trial court found it relevant that the LEMA was not permanent and concluded that further reductions in water permits are not a taking because all economic benefits of the water have been eliminated. The plaintiffs claimed that the appeal process for the LEMA was inadequate because it did not provide for review by an independent unbiased tribunal. The trial court disagreed, noting that state law provides for judicial review. Also, the trial court determined that the recordkeeping requirements of irrigators was not unconstitutionally vague. The LEMA allows irrigators two ways to record water usage, inspect and record meter readings on a bi-weekly basis or "install or maintain an alternative method of recording," other than the meter that is sufficient to be used to determine operating time in the event of a meter failure."
On the claim that the CE did not follow proper procedure when implementing the LEMA plan, the trial court determined that state law did not require the CE to include findings of fact or law in notice letters. In addition, the final orders did not need to consider constitutional concerns as those are properly reserved for a court. Likewise, the trial court held that the CE did not unlawfully delegate oversight of the LEMA hearing, and that the creation of the district-wide LEMA was not done in a manner that was arbitrary and capricious.
The Kansas case is the opening round in what will likely be lengthy litigation on the issue of how far a state can go in regulating existing, vested water rights. As the litigation proceeds, the state might do well to remember that for an alleged regulatory taking of private property rights by the state, disaffected parties no longer need to endure state court litigation on the taking issue before seeking compensation in the federal court system. Knick v. Township of Scott, 139 S. Ct. 2162 (2019).
Wednesday, October 23, 2019
In 1972, comedian George Carlin listed in a monologue the “Seven Words You Can Never Say on Television.” He then proceeded to use all seven words multiple times. The use of those words constitutes a violation of Federal Communications Commission standards and triggers a penalty. In the tax world, there are also “dirty” words, and they are used to describe something that happens in tax that triggers a bad tax result for the taxpayer. “Recapture” is one of those words. It means that a tax benefit previously received must be given up – paid back. That “pay back” is often at ordinary income tax rates rather than the (often) more favorable capital gain rates.
Recapture in the context of depletion deductions previously claimed that is associated with oil and gas interests – it’s the topic of today’s post.
Recapture – What Is It?
At its core, recapture is the Code’s procedure for triggering income on a gain a taxpayer realizes upon the disposition of an asset that had previously provided a tax benefit, such as through depreciation. Because depreciation can be deducted from ordinary income to reflect the wear-and-tear on an asset (an exhaustion factor) used in the taxpayer’s trade or business or for the production of income where the asset has a determinable useful life of more than one year, gain on the disposal of the asset (up to the taxpayer’s recomputed basis in the asset (see, e.g. I.R.C. §1016 and/or I.R.C. §1245(a)(2)(A)) must be reported as ordinary income. It is not reported as capital gain in accordance with I.R.C. §1231. Depreciation recapture attributable to tangible personal property is governed by I.R.C. §1245. The provision governing recapture associated with real property is I.R.C. §1250. For I.R.C. §1250 recapture purposes, the IRS refers to it as “additional depreciation” in IRS Pub. 544. In I.R.S. Pub. 544, the IRS describes it as the portion of accumulated depreciation that exceeds straight line depreciation. It is taxed at ordinary income rates to the extent of gain realized at a maximum of 37 percent (presently). The portion corresponding to straight-line depreciation is “unrecaptured §1250 gain” and is taxed at a maximum rate of 25 percent. Any remaining gain is long-term capital gain if the taxpayer had held the property for over a year, and is taxed at a maximum capital gain rate of 20 percent.
Depletion Deduction Recapture
There’s another recapture section of the Code – I.R.C. §1254. It’s titled, “Gain from disposition of interest in oil, gas, geothermal, and other mineral properties.” While gain on the sale or exchange of natural resources is generally capital gain in nature via I.R.C. §1221 or I.R.C. §1222 or via the netting process of I.R.C. §1231, I.R.C. §1254 taxes as ordinary income the recapture of depletion deductions previously claimed when an oil or gas interest is disposed of in a taxable transaction. Under I.R.C. §1254, the amount recaptured as ordinary income is the lesser of (1) the sum of the deductions for depletion under I.R.C. §611 that reduced the property’s adjusted basis, and the intangible drilling and development costs currently deducted under I.R.C. §263; or (2) the gain obtained by deducting the adjusted basis of the property from the amount realized. I.R.C. §§1254(a)(1)(A),(B).
Because I.R.C. §1254 applies to depletion that reduces adjusted basis, it applies to both percentage and cost depletion – to the extent either depletion approach reduced the adjusted basis of the subject property. Thus, gain in excess of depletion previously allowed is taxed as ordinary income. It also applies separately to each property of the taxpayer, if the taxpayer has more than a single property. I.R.C. §614 defines “property” for this purpose. Also, if the taxpayer only disposes of a portion of a property that is subject to I.R.C. §1254 depreciation recapture, rules governing partial dispositions can apply. See I.R.C. §1254(a)(2); Treas. Reg. §1.1254-1(c).
Consider the following example:
Suzy, in 2011, acquired a working interest in an oil and gas deposit. Her original basis in the interest was $100,000. During Suzy’s period of ownership, she was allowed (and claimed) $75,000 of depletion deductions. Thus, her adjusted basis in the working interest is $25,000 in accordance with I.R.C. §1016(a)(2). Suzy did not expense any intangible drilling and development costs. Suzy later sells her working interest in the deposit in 2019 for $125,000 - its fair market value at the time of sale. Suzy has realized gain of $125,000 less her adjusted basis of $25,000, or $100,000. Applying I.R.C. §1254(a)(1), Suzy has recapture of the previously claimed depletion deductions of the lesser of $75,000 or $100,000. Thus, $75,000 of the $100,000 gain is treated as ordinary income. The remaining $25,000 gain is taxed as long-term capital gain in accordance with I.R.C. §1231.
Other Rules on Recapture
As noted above, recapture is potentially triggered when the taxpayer’s interest is disposed of in a taxable transaction. In other words, there must be a “disposition” of the asset before recapture is possible. Some transactions do not constitute a “disposition” for purposes of recapture under I.R.C. §1254. These include mortgaging the property (Treas. Reg. §1.1254-1(b)(3)(ii)(A)); any abandonment (unless the taxpayer recognizes income on the foreclosure of a nonrecourse debt) (Treas. Reg. §1.1254-1(b)(3)(ii)(B)); leasing or subleasing the property (Treas. Reg. §1.1254-1(b)(3)(ii)(C)); the termination or election of S corporation status (Treas. Reg. §1.1254-1(b)(3)(ii)(D)); including the property in a pooling or unitization arrangement (Treas. Reg. §1.1254-1(b)(3)(ii)(E)); the expiration or reversion of an operating mineral interest in whole or in part by the terms of the agreement (Treas. Reg. §1254-1(b)(3)(ii)(F)); or any conversion of an overriding royalty interest that at the grantor’s option (or at the option of a successor in interest) converts to an operating mineral interest after a certain amount of production. Treas. Reg. §1.1254-1(b)(3)(ii)(G). Also, when taxpayers exchange their interests in oil and gas partnerships for stock of a newly organized corporation, they don’t have any gain or loss except to the extent that their share of partnership liabilities exceed their basis. In this situation, there is no recapture of intangible drilling costs. Priv. Ltr. Rul. 8107099 (Nov. 21, 1980).
If the disposition of the oil or gas (or geothermal) property is by gift, recapture is not triggered. Treas. Reg. §1.1254-2(a)(1). But if the transaction is a part gift/part sale transaction (typically utilized in estate planning situations and other transactions involving family members) recapture can apply to any gain that the transaction triggers. Treas. Reg. §1.1254-2(a)(2). The charitable deduction associated with a gift to a charitable organization of a working or operating interest in an oil or gas property must be reduced by the amount of any intangible drilling and development costs attributable to the donated interest that the donor previously deducted under I.R.C. §1254. I.R.C. §170(e)(1)(A).
As usual, a transfer on account of death does not trigger recapture. Treas. Reg. §1.1254-2(b). Also, if the disposition occurs as part of a like-kind exchange under I.R.C. §1031, the depreciation recapture taxed as ordinary income is limited to the “boot” (gain attributable to “unlike” property) involved in the exchange. Treas. Reg. §1.1254-2(c). On this last point, it appears to be implicit in the regulation that an interest in an oil and gas property constitutes real estate for purposes of I.R.C. §1031. That’s an important point now that personal property is not eligible for tax-deferred treatment under I.R.C. §1031.
When a partnership disposes of an interest in oil and gas (or other natural resources), the amount treated as ordinary income is determined at the partner level. Each partner recognizes as ordinary income the lesser of the partner’s I.R.C. §1254 costs with respect to the property disposed of, or the partner’s share of the amount (if any) by which the amount realized upon the sale, exchange, or involuntary conversion, or the fair market value of the property upon any other disposition, exceeds the adjusted basis of the property. Treas. Reg. §1.1254-5(b)(1).
Oil and gas taxation is a bit unique in many respects. Depletion, while conceptually the same as depreciation, is nuanced. The rules on recapture of the depletion deduction generally follow the rules for depreciation recapture. That means if the rules are triggered, the result is not going to be a good one for the taxpayer. Remember, “recapture” is one of the “dirty” words in tax. Avoid it if you can.
Monday, October 21, 2019
Last week’s post on cost depletion generated an interesting question from a reader concerning whether a bonus payment that a landowner receives upon signing an oil and gas lease agreement entitles the landowner to a cost depletion deduction on the payment. That’s an important question. The increased production of oil and gas on privately owned property in recent years means that an increasing number of landowners are receiving payments from oil and gas companies, including bonus payments.
The taxation of bonus payments associated with oil and gas leases – that’s the topic of today’s post.
Character of the gain. The lessee typically pays a lump-sum cash bonus during the initial lease term (pre-drilling) for the rights to acquire an economic interest in the minerals. This is the basic consideration that the lessee pays to the lessor (landowner) when the lease is executed. The lessor reports the bonus payment on Schedule E, Supplemental Income and Loss. It constitutes net investment income (NII) that is potentially subject to the additional 3.8 percent NII tax (NIIT) of I.R.C. §1411. A bonus payment is generally categorized as ordinary income and not capital gain because it is not tied to production. See, e.g., Dudek v. Comr., T.C. Memo. 2013-272, aff’d., 588 Fed. Appx. 199 (3d Cir. 2014).
A bonus payment may be paid annually for a fixed number of years regardless of production. If the lessee cannot avoid the payments by terminating the lease, the payments are termed a lease bonus payable in installments. These payments are also consideration for granting a lease. They are an advance payment for oil, and each installment is typically larger than a normal delay rental. A cash-basis lessee must capitalize such payments, and the fair market value (FMV) of the contract in the year the lease is executed is ordinary income to the lessor if the right to the income is transferable. Rev. Rul. 68-606, 1968-2 CB 42. However, if the bonus payments are made under a contract that is nontransferable and nonnegotiable, a cash-basis lessor can defer recognizing the payments until they are received. See, e.g., Kleberg v. Comm’r, 43 BTA 277 (1941), non. acq. 1952-1 CB 5.
Cost depletion? Can a lessor claim cost depletion on a bonus payment? This question came up in a Tax Court case in 2013. In Dudek v. Comr., T.C. Memo. 2013-272, aff’d., 558 Fed. Appx. 199 (3d Cir. 2014), the taxpayer owned a tract of land in Pennsylvania and entered into an oil and gas agreement with an oil and gas company. The lease called for the taxpayer to receive a lease bonus payment upfront for entering into the lease agreement. The taxpayer was also entitled to a royalty payment of 16 percent of the net profits of oil and gas extracted from the leased premises. The bonus payment was not tied to extraction or production in any fashion. It was purely an upfront payment made to induce the taxpayer to execute the lease agreement. The taxpayer reported the bonus payment as long-term capital gain rather than ordinary income on the assertion that the transaction amounted to a sale of oil and gas. On audit, the IRS disagreed, recharacterized the bonus payment as ordinary income and slapped a 20 percent accuracy-related penalty on top.
The Tax Court agreed with the IRS, citing the classic U.S. Supreme Court case of Burnet v. Hamel, 287 U.S. 103 (1932). On the sale/lease issue, the Tax Court taxpayer retained an economic interest in the oil and gas deposits that were the subject matter of the lease. That was true, the Tax Court reasoned because under the lease the taxpayer was entitled to royalty payments computed as a percentage of net profits of oil and gas that were extracted from the property. That meant that the taxpayer possessed an economic interest in the in-place minerals. See, e.g., Kittle v. Comr., 21 T.C. 79 (1953). Had the transaction been a sale, the Tax Court reasoned, there would have been an exchange of a set quantity of oil and gas for a particular price.
The taxpayer also claimed that the bonus income was subject to percentage depletion. Percentage depletion is a cost recovery method that provides a tax deduction for most natural resources. Percentage depletion assigns a set percentage of depletion to the gross income derived from extracting fossil fuels, minerals, or other nonrenewable resources. For oil and gas, the allowable statutory percentage depletion deduction is the lesser of net income or 15% of gross income. If net income is less than 15% of gross income, the deduction is limited to 100% of net income. I.R.C. §613(b)(2). The Tax Court disagreed with the taxpayer’s claim that percentage depletion applied. I.R.C. §613A(d) bars percentage depletion from applying to lease bonus payments. The payment must be tied to production for percentage depletion to apply. See Treas. Reg. §1.613A-3(j).
But the Tax Court did indicate that the taxpayer’s bonus payment could be eligible for cost depletion. The Tax Court noted that cost depletion, in accordance with Treas. Reg. §1.612-3(a)(1), is tied to the taxpayer’s basis for depletion. The amount of the deduction is dependent upon depletion basis, future expected royalties and the amount of the upfront bonus payment. The taxpayer needed to establish all of these amounts to claim a deduction for cost depletion. The taxpayer failed to do so. The Tax Court also upheld the accuracy-related penalty.
The Dudek case makes it clear that the taxpayer must establish a basis in the minerals subject to an oil and gas lease agreement to be able to claim cost depletion. That can be tricky when land is acquired that has an oil and gas deposit and purchase transaction combines both the land and the deposit together. It is the position of the IRS that minerals do not have a separate cost basis unless the seller’s cost stipulated such an amount; or was the result of an estate tax valuation that contained the separate valuations; or the seller’s cost basis can be properly allocated in accordance with existing evidence at the time of the acquisition. I.R.M. 22.214.171.124.1.2 (Dec. 3, 2013). While the IRS has indicated that a taxpayer might be able to establish a separate value for the minerals based on the evidence, it clearly is the taxpayer’s burden to prove the basis allocated to the oil and gas (or other mineral) deposit. See, e.g., Rev. Rul. 69-539, 1969-2 CB 141; Collums v. United States, 480 F. Supp. 864 (D. Wyo. 1979). That allocation might even be 100 percent of the taxpayer’s basis in the lease if a zero estimate of future royalties is reasonable (such as in a wildcat area). See, e.g., Collums v. United States, 480 F. Supp. 864 (D. Wyo. 1979); but see Tech. Adv. Memo. 8532011 (May 7, 1985).
Cost depletion can be confusing. The Dudek opinion reiterates the long-standing ordinary income treatment of bonus payments associated with oil and gas leases. It also points out that cost depletion can apply to the payments. But work must be done to be able to claim cost depletion, and that burden is on the taxpayer.
Thursday, October 17, 2019
When financial and economic conditions sour, one of the issues that can come up concerns the ability to collect on debts. Ag retail businesses are experiencing tougher credit relations with farm clients due to difficult times in some sectors of production agriculture. Thus, a debt can turn into a “bad debt.” That has tax consequences. An income tax deduction is allowed for debts which become worthless within the taxable year.
What does it take to be able to deduct a bad debt? Is there a tax difference between a business bad debt and a non-business bad debt?
Distinguishing between business and non-business bad debts. That’s the topic of today’s blog post.
Elements Necessary For Deductibility
Debtor-creditor relationship. For a bad debt to be deductible, there must be a debtor-creditor relationship involving a legal, valid, and enforceable obligation to pay a fixed or determinable sum of money. See, e.g., Meier v. Comm’r, T.C. Memo. 2003-94; Treas. Reg. §1.166-1(c). In addition, the taxpayer must be able to show that it was the intent of the parties at the time the transaction was entered into to create that debtor-creditor relationship. The requisite intent is established by showing that when the relationship was formed, the taxpayer had an actual expectation of repayment and intended to enforce the debt if necessary. Thus, a deductible bad debt can derive from a loan made in the context of protecting the taxpayer’s investment if the purpose of making the loan was for business and their was intent to collect on the loan if necessary.
While a formal loan agreement helps establish this intent, the lack of one will not absolutely bar the finding of a bona fide debt. Conversely, the existence of paperwork documenting the transaction (such as a note) does not always mean that the transaction constitutes a bona fide debt stemming from a debtor-creditor relationship.
Related party? The fact that the debtor and creditor are related parties does not preclude a bad debt deduction. The key is whether the loan that is now worthless was made for legitimate business purposes and arises from a debtor-creditor relationship and meets the other requirements as noted above. However, the IRS tends to look more closely to debts involving related parties than those involving non-related parties.
Classification of Bad Debts
For individuals and entities taxed as individuals, bad debts may be business bad debts or nonbusiness bad debts. Corporations have only business bad debts. Business bad debts are deducted directly from gross income while a nonbusiness bad debt of a non-corporate taxpayer is reported as a short-term capital loss when it becomes totally worthless.
So what is the distinction between a business bad debt and a nonbusiness bad debt? A business bad debt relates to operating a trade or business and is mainly the result of credit sales to customers or loans to suppliers, clients, employers or distributors. The loan transaction must have a relationship to the taxpayer’s trade or business. Treas. Reg. §1.166-5(b). According to the U.S. Supreme Court, the relationship of the loan transaction to the taxpayer’s trade or business is dependent upon whether the taxpayer’s “dominant motivation” for the loan was related to the taxpayer’s business. United States v. Generes, 405 U.S. 93 (1972). In Generes, the Court concluded that the taxpayer's status as an employee was a business interest, but the taxpayer’s status as a shareholder was a nonbusiness interest. But, this does not appear to be a blanket rule for every situation. While the Court indicated that a business bad debt can arise from a loan transaction entered into to protect an employment status, source of income, a business relationship or to protect a business reputation, the Court also seemed to indicate that a shareholder can still experience a business bad debt if the loan transaction has a business purpose and otherwise meets the requirements of a business bad debt. The facts are critical.
A taxpayer that is in the trade or business of lending money generally treats uncollectable loans as business bad debts. See, e.g., Henderson, 375 F.2d 36 (5th Cir. 1967); Serot v. Comr., T.C. Memo. 1994-532; aff’d. without pub. op., 74 F.3d 1227 (3d Cir. 1995); Owens v. Comr., T.C. Memo. 2017-157. The cases cited also provide good guidance on how much loan activity is necessary for a taxpayer to be treated as being in the trade or business of lending money.
Claiming the Deduction
A bad debt deduction may be claimed only if there is an actual loss of money or the taxpayer has reported the amount as income. A business bad debt may be totally worthless (no collection potential) or partially worthless. I.R.C. §166(a)(1)-(2). In any event, the allowed deduction for a bad debt does not include any amount that was deducted in a prior year at a time that the debt was only partially worthless. Treas. Reg. §1.166-3(b).
A bad debt is deductible when worthlessness can be established. A nonbusiness bad debt must be wholly worthless in the year for which the deduction is claimed. Cooper v. Comr., T.C. Memo 2015-191; Treas. Reg. §1.165-5(a)(2). But, the actual tax year of worthlessness can sometimes be difficult to determine. If the IRS, on audit, views worthlessness to have occurred in a year before the bad debt deduction was actually claimed, the applicable statute of limitation for seeking a refund or credit for a bad debt is seven years (rather than the normal three years). I.R.C. §6511(d).
But, a bad debt can’t be claimed if the taxpayer doesn’t have any records or activity to establish that the money transferred created an enforceable loan entered into for profit. That can be a key point with many farming operations and loans between family members. See, e.g., Vaughters v. Comr., T.C. Memo. 1988-276. It’s critical to properly document the arrangement.
Careful tax planning can help maximize the tax benefit of a bad debt deduction and minimize the economic pain. Today’s post covered the basics of bad debts, perhaps a future post can dig a little further.
Tuesday, October 15, 2019
A taxpayer that is engaged in a trade or business can recover the cost of a business asset through depreciation. In other words, an asset is not depreciable unless it is used in the taxpayer’s trade or business or used for the production of income. In essence, the depreciation deduction is to account for the wear-and-tear of the asset as it is used in the business or to produce income for the taxpayer. But, the asset must have a determinable useful life of more than one year. Land, for example, is not depreciable because it does not have a determinable useful life.
But, there are other business and/or income-producing assets that are not eligible for depreciation. For example, natural resources such as sand and gravel deposits, as well as deposits for oil and gas are not depreciated. But don’t these assets wear out? They do and can be eligible for a depletion allowance. The deductible allowance for depletion is computed differently than is the deduction for depreciation. One method of computing it is called “cost depletion.”
The cost depletion method of computing deductions associated with oil, gas and other minerals – it’s the topic of today’s post.
Depletion is the descriptive term for the using of a natural resource by mining, drilling, quarrying or the like. A depletion allowance allows the owner of the resource to recover the cost of the reduction of reserves of the resource as production and sales occur. To be a resource “owner” entitled to a claim depletion, the taxpayer must have an “economic interest” in the natural resource as an owner, and the legal right to the income from the extraction of the minerals. In addition, a depletion deduction is only allowed when there is production and sale activity from the minerals which provides income to the taxpayer for the tax year.
As noted, a taxpayer is entitled to recover the taxpayer’s cost basis in natural resources over the life of the resources. The cost depletion method of computing that cost recovery is tied to the quantity of the resource sold each year. There are unique rules that can apply when determining cost depletion on production payments, advance royalties, bonuses. In addition, sometimes the computational rules are different depending upon the particular natural resource involved. These unique aspects are beyond the scope of today’s post.
Via cost depletion, the taxpayer recovers the taxpayer’s capital investment (i.e., tax basis) in the minerals while the minerals produce income. Thus, with respect to oil and gas, for example, the cost basis of the property must be allocated between the land and the associated capital assets that were acquired with the land purchase – fences; tile lines; buildings; equipment; and the mineral deposit. The use of the cost depletion method is dependent upon having made these allocations.
Under the cost depletion approach, the taxpayer annually deducts a portion of the taxpayer’s capital investment, less prior deductions, that equal the fraction of the estimated remaining recoverable reserves that have been produced and sold during that particular year. Over the life of the deposit, the total cumulative amount recovered under the cost depletion method cannot exceed the taxpayer’s capital investment.
The IRS does not provide a form for computing the cost depletion deduction. However, a formula is utilized to make the computation. Under the formula, the deposit’s adjusted basis is divided by the units of the mineral deposit that remain as of the end of the tax year (i.e., total recoverable units). The result of that is known as the “depletion unit” or a rate per unit. That amount is then multiplied by the units of mineral that were sold within the tax year based on the taxpayer’s accounting method. The taxpayer bears the burden of establishing basis, remaining units and the units sold during the year. Treas. Reg.§1.612-1(b)(1)(i).
With respect to oil and gas, cost depletion is computed with respect to each oil and gas property by reference to the total number of recoverable units that the property is estimated to contain, and the number of units sold from the property during the tax year. Treas. Reg. §1.611-2(a). An account is to be maintained for each property and annually adjusted for units sold and for depletion claimed. Treas. Reg. §1.611-2(a). The total recoverable units is the sum of the number of units that remain at year end plus the number of units of minerals sold during the tax year. The landowner must determine the recoverable units of minerals via industry custom, and can utilize (by election) an IRS safe harbor. See Rev. Proc. 2004-19, 2004-10 IRB 563.
Consider the following example:
Jed buys a tract of land that contains a mineral deposit of sand and gravel. Jed paid $500,000 for the tract, and his accountant allocated $125,000 to the land and $375,000 to the minerals. Jed hired other experts to measure the amount of the marketable minerals via a geological survey and they determined that the deposit contained $100,000 tons of marketable minerals. During the year, 5,000 tons of minerals were mined and sold. Jed’s cost depletion deduction would be computed as follows: $375,000/$100,000 x 5,000 = $18,750.
In the second year (Year 2), another 5,000 tons of the sand and gravel are mined and sold. In Year 2, the property's basis has been reduced to $356,250 by the depletion allowed in the first year. Also, the units remaining as of the tax year have been reduced to 95,000 by the units sold in the first year. The cost depletion deduction in Year 2 would be $18,747.37 ($356,200/95,000 x 5,000).
The Importance of Basis
Clearly, properly computing income tax basis is critical to determining the proper depletion deduction. The basis number only applies to the mineral property. Thus, it doesn’t include non-mineral real estate or non-mineral assets that aren’t used for producing minerals. It also doesn’t include the residual value of land and improvements when operations end. Treas. Reg.§1.612-1(b)(1)(ii). But, it does include capitalized drilling and development costs recoverable through depletion. Treas. Reg.§1.612-1(b)(1).
Adjustments to basis will occur over time and include (as applied to oil and gas) oil and gas drilling and development costs that were capitalized. But, not included in any basis adjustment are any mineral exploration and development expenses that are treated as deferred expenses and any basis of depreciable property that is leased together with depletable mineral property. Treas. Reg. §1.612-1(b)(1).
Deductions for cost depletion stop once the sum of the depletion deductions equals the cost or other basis of the property plus allowable capital additions. Treas. Reg. §1.611-2(b)(2).
Recordkeeping is essential. The basis of the depletable property is to be recorded in a separate account, along with any capital additions and adjustments. Treas. Reg. §1.611-2(b)(1). If that’s not done, the cost depletion deduction may be lost for the tax year and/or upon later disposition of the property. See, e.g., Winifrede Land Company, 12 T.C.M. (CCH) 289 (1953).
Last year, I devoted a post to the issue of depletion of minerals. https://lawprofessors.typepad.com/agriculturallaw/2018/07/the-depletion-deduction-for-oil-and-gas-operations.html. Today’s post took a bit of a closer look at one aspect of depletion – cost depletion. The depletion deduction can be complicated, but when big dollars are involved, getting it right matters.
Friday, October 11, 2019
The power to “take” private property for public use (or for a public purpose) without the owner's consent is an inherent power of the federal and state governments. However, the United States Constitution limits the government's eminent domain power by requiring federal and state governments to pay for what is “taken.” The Fifth Amendment states in part “...nor shall private property be taken for public use without just compensation.”
Whether a taking has occurred is not an issue when the government physically takes the property, with the only issue being whether the taking is compensable and the amount of compensation due to the landowner. However, for non-physical (regulatory) takings, the issue is murkier. At what point does government regulation of private property amount to a compensable taking? In a previous post I addressed U.S. Supreme Court guidance on how to determine the property that the landowner claims has been taken.
If the taking is by a state or local government, must the landowner “exhaust” state court remedies before seeking compensation for a regulatory taking? If so, it could result in a landowner having no real access to the federal court system on a constitutional taking claim. It’s an issue that the U.S. Supreme Court addressed late in its last term this past June. It’s also the topic of today’s post – pursuing a “takings” remedy in federal court for a state/local-level regulatory taking
Regulatory (Non-Physical) Takings
A non-physical taking may involve the governmental condemnation of air space rights, water rights, subjacent or lateral support rights, or the regulation of property use through environmental restrictions. How is the existence of a regulatory taking determined? There are several approaches that the Supreme Court has utilized.
Multi-factor balancing test. In a key case decided in 1978, the U.S. Supreme Court set forth a multi-factored balancing test for determining when governmental regulation of private property effects a taking requiring compensation. In Penn Central Transportation Co. et al. v. New York City, 438 U.S. 104 (1978), the Court held that a landowner cannot establish a “taking” simply by being denied the ability to exploit a property interest believed to be available for development. Instead, the Court ruled that in deciding whether particular governmental action effects a taking, the character, nature and extent of the interference with property rights as a whole are the proper focus rather than discrete segments of the owner’s property rights. In 2005, the Court confirmed the multi-factor test and noted that the touchstone for deciding when a regulation is a taking is whether the restriction on property usage is functionally equivalent to a physical taking of the property. Lingle, et al. v. Chevron U.S.A., Inc., 544 U.S. 528 (2005).
Total regulatory taking. In Lucas v. South Carolina Coastal Council, 505 U.S. 1003 (1992), the landowner purchased two residential lots with an intent to build single-family homes. Two years later, the state legislature passed a law prohibiting the erection of any permanent habitable structures on the Lucas property. The law's purpose was to prevent beachfront erosion and to protect the property as a storm barrier, a plant and wildlife habitat, a tourist attraction, and a “natural health environment” which aided the physical and mental well-being of South Carolina's citizens. The law effectively rendered the Lucas property valueless. Lucas sued the Coastal Council claiming that, although the act may be a valid exercise of the state's police power, it deprived him of the use of his property and thus, resulted in a taking without just compensation. The Coastal Council argued that the state had the authority to prevent harmful uses of land without having to compensate the owner for the restriction.
The Supreme Court ruled for Lucas and opined that the state's interest in the regulation was irrelevant since the trial court determined that Lucas was deprived of any economically viable alternative use of his land. The Lucas case has two important implications for environmental regulation of agricultural activities. First, the Lucas court focused solely on the economic viability of the land and made no recognition of potential noneconomic objectives of land ownership. However, in the agricultural sector land ownership is typically associated with many noneconomic objectives and serves important sociological and psychological functions. Under the Lucas approach, these noneconomic objectives are not recognized. Second, under the Lucas rationale, environmental regulations do not invoke automatic compensation unless the regulations deprive the property owner of all beneficial use.
Under the Lucas approach, an important legal issue is whether compensation is required when the landowner has economic use remaining on other portions of the property that are not subject to regulation.
Unconstitutional conditions. In Nollan v. California Coastal Commission,483 U.S. 825 (1987), the plaintiff owned a small, dilapidated beach house and wanted to tear it down and replace it with a larger home. However, the defendant was concerned about preserving the public's viewing access over the plaintiff's land from the public highway to the waterfront. Rather than preventing the construction outright, the defendant conditioned the plaintiff's right to build on the land upon the plaintiff giving the defendant a permanent, lateral beachfront easement over the plaintiff's land for the benefit of the public. Thus, the issue was whether the state could force the plaintiffs to choose between their construction permit and their lateral easement. The Court held that this particular bargain was impermissible because the condition imposed (surrender of the easement) lacked a “nexus” with, or was unrelated to the legitimate interest used by the state to justify its actions - preserving the view. The Court later ruled similarly in Dolan v. Tigard, 512 U.S. 374 (1994). These cases hold that the government may not require a person to give up the constitutional right to receive just compensation when property is taken for a public use in exchange for a discretionary benefit that has little or no relationship to the property. The rule of the cases does not apply to situations involving impact fees and other permit conditions that do not involve physical invasions, but it would apply to monetary exactions where none of the plaintiff’s property is actually taken. See, e.g., Koontz v. St. Johns River Water Management District, 133 S. Ct. 2586 (2013).
State/Local Takings – Seeking a Remedy
For a landowner that has sustained a state/local regulatory (or physical) taking, can compensation be sought initially in federal court or must legal procedures be first pursued in state court with federal courts only available if compensation is denied at the state level? The U.S. Supreme Court answered this question in 1985. In Williamson Regional Planning Commission v. Hamilton Bank of Johnson City, 473 U.S. 172 (1985), the Court held that if a state provides an adequate procedure for seeking just compensation, there is no Fifth Amendment violation until the landowner has used the state procedure and has been denied just compensation. However, 28 U.S.C. §1738, would then be applied with the resulting effect that the failure to receive compensation at the state level generally meant that there was no recourse in the federal courts because of the preclusive effect of the landowner having already litigated the same issue(s) in the state courts. See, e.g., San Remo Hotel L.P., v. City and County of San Francisco, 545 U.S. 323 (2005). This “catch-22” was what the Court examined earlier this year.
The 2019 Case
In Knick v. Township of Scott, 139 S. Ct. 2162 (2019), the plaintiff owned a 90-acre farm in Pennsylvania on which she grazed horse and other animals. The farm includes a small graveyard where ancestors of the plaintiff’s neighbors were buried. Such “backyard burials” are permissible in Pennsylvania. In late 2012, the defendant passed an ordinance requiring that “[a]ll cemeteries…be kept open and accessible to the general public during daylight hours.” The ordinance defined a “cemetery” as “[a] place or area of ground, whether contained on private or public property which has been set apart for or otherwise utilized as a burial place for deceased human beings.” In 2013, the defendant notified the plaintiff of her violation of the ordinance. The plaintiff sued in state court for declaratory and injunctive relief on the basis that the ordinance amounted to a taking of her property, but she did not seek compensation via an inverse condemnation action.
While the case was pending, the defendant agreed to not enforce the ordinance. As a result, the trial court refused to rule on the plaintiff’s action. Without any ongoing enforcement of the ordinance, the plaintiff couldn’t show irreparable harm. Without irreparable harm, the court noted, the plaintiff couldn’t establish what was necessary for the equitable relief she was seeking. Frustrated at the result in state court, the plaintiff filed a takings claim in federal court. However, the federal trial court dismissed the case because she hadn’t sought compensation at the state level. Knick v. Scott Township, No. 3:14-CV-2223st (M.D. Pa. Oct. 29, 2015). The appellate court affirmed, citing the Williamson case. Knick v. Township of Scott, 862 F.3d 310 (3d Cir. 2017).
In a 5-4 decision, Chief Justice Roberts (joined by Justices Alito, Gorsuch, Kavanaugh and Thomas), writing for the majority, reversed. He pointed out that there is a distinction between the substance of a right and the remedy for the violation of that right. It’s the takings clause of the Fifth Amendment that establishes that the government can only take (either physically or via regulation) private property by paying for it. The government’s infringement on private property is what triggers possible compensation. The Constitutional violation has occurred and a state court decision that makes the landowner financially whole simply remedies that violation. It doesn’t redefine the property right. Thus, the majority opinion reasoned, laws confer legal rights and when those rights are violated there must be legal recourse. See, e.g., Marbury v. Madison, 5 U.S. 137 (1803). As the majority noted, “a government violates the Takings Clause when it takes property without compensation, and…a property owner may bring a Fifth Amendment claim [in federal court]… at that time.”
The Court’s decision is a significant win for farmer’s, ranchers, and other rural landowners that are impacted by state and local regulations impacting land use. A Fifth Amendment right to compensation accrues at the time the taking occurs. It’s also useful to note that the decision would not have come out as favorably without the presence of Justices Gorsuch and Kavanaugh on the Court. That’s a point that agricultural interests also note.
Wednesday, October 9, 2019
Agricultural law issues in the courts are many. On a daily basis, cases involving farmers, ranchers, rural landowners and agribusinesses are decided. Periodically, on this blog I examine a few of the recent court decisions that are of particular importance and interest. Today’s post is one such post.
Proving water drainage damage; migrating gas and the rule of capture; and suing for Clean Water Act (CWA) – these are the topics of today’s post.
The Case of the Wayward Water
In Kellen v. Pottebaum, 928 N.W.2d 874 (Iowa Ct. App. 2019), the defendant installed a drain pipe that discharged water from the defendant’s land to the plaintiffs’ land. The plaintiff sued alleging that the pipe caused an unnatural flow of water which damaged the plaintiff’s farmland and sought damages and removal of the pipe. The defendant counterclaimed arguing that the plaintiff’s prior acts and/or inaction regarding the flow of the water caused damage to the defendant’s property. The trial court determined that neither party had established their claims and dismissed each claim with prejudice.
The appellate court affirmed. As for the sufficiency of the evidence, the appellate court noted that the defendant owned the dominant estate and the plaintiff owned the servient estate. As such, if the plaintiff could prove that the installation of the pipe considerably increased the volume of water flowing onto the plaintiff’s land or substantially changed the drainage and actual damage resulted, the plaintiff would be entitled to relief. However, most of the evidence presented to the court was the observations of lay witnesses rather than measured water flow. Accordingly, the appellate court agreed with the trial court that the plaintiff did not prove by a preponderance of the evidence that installation of the pipe caused the increased water flow. The appellate court noted that a “reasonable fact finder” could attribute the additional water on the plaintiffs’ property to the increased rain fall during the years at issue. The appellate court also determined that the plaintiffs did not prove by preponderance of the evidence that installation of the pipe substantially changed the drainage. The water did not flow in a different direction on the plaintiff’s property. Rather, the defendant altered the flow of water across his property in a natural direction towards the plaintiff’s drainage, which is permissible under state (IA) law. Thus, the plaintiff did not prove harm by a preponderance of the evidence. The appellate court also concluded that the trial court did not abuse its discretion excluding some of the plaintiff’s evidence.
Ownership of Migrated Gas
In Northern Natural Gas Co. v. ONEOK Field Servs. Co., LLC, No. 118,239, 2019 Kan. LEXIS 324 (Kan. Sup. Ct. Sept. 6, 2019), the plaintiff operated an underground gas storage facility, which was certified by the proper state and federal commissions. The defendants were producers with wells located two to six miles from the edge of the plaintiff’s certified storage area. Stored gas migrated to the defendants’ wells and the defendants captured and sold the gas as their own. The plaintiff sued for lost gas sales and the defendants moved for summary judgment on the grounds that the Kansas common law rule of capture allowed the gas extraction. The trial court granted the defendants’ motion. Two years later, the plaintiff received certification to expand the storage area into the areas with the defendants’ wells. Another dispute arose as to whether the defendants could capture the gas after the plaintiff’s storage area was expanded. The trial court held that the defendants could under the common law rule of capture.
On review, the Kansas Supreme Court reversed and remanded on the basis that the rule of capture did not apply. That rule, the Court noted, allows someone that is acting within their legal rights to capture oil and gas that has migrated from the owner’s property to use the migrated oil and gas for their own purposes. The rule reflects the application of new technology such as injection wells and applies to non-native gas injected into common pools for storage. However, the Court reasoned, the rule does not apply when a party (such as the plaintiff) is authorized to store gas and the storage is identifiable. The Court determined that state statutory law did not override this recognized exception to the application of the rule of capture. The Court remanded the case for a computation of damages for the lost gas.
Jurisdiction Over CWA §404 Permit Violations – Who Can Sue?
A recent case involving a California farmer has raised some eyebrows. In the case, the trial court allowed the U.S. Department of Justice (DOJ) to sue the farmer for an alleged CWA dredge and bill permit violation without a specific recommendation from the Environmental Protection Agency (EPA). The farmer was alleged to have discharged “pollutants” into a “waters of the United States” (WOTUS) as a result of tractor tillage activities on his farmland containing or near to wetlands contiguous to a creek that flowed into a WOTUS. Staff of the U.S. Army Corps of Engineers (COE) saw the tilled ground and investigated. The COE staff then conferred with the EPA and then referred the matter to the U.S. Department of Justice (DOJ). The DOJ sued (during the Obama Administration) for enforcement of a CWA §404 permit “by the authority of the Attorney General, and at the request of the Secretary of the Army acting through the United States Corps of Engineers.” The DOJ alleged that the equipment "constituted a 'point source'" pollutant under the CWA and "resulted in the placement of dredged spoil, biological materials, rock, sand, cellar dirt or other earthen material constituting “pollutants” (within the meaning of 33 U.S.C. § 1362(6) into waters of the United States. The DOJ alleged that the defendant impacted water plants, changed the river bottom and/or replaced Waters of the United States with dry land, and "resulted in the 'discharge of any pollutant' within the meaning of 33 U.S.C. § 1311(a)."
The defendant moved for summary judgment on the basis that the CWA authorizes only the EPA Administrator to file a CWA §404 enforcement action and that the court, therefore, lacked jurisdiction. The court disagreed with the defendant on the basis that 28 U.S.C. §1345 conferred jurisdiction. That statute states, “Except as otherwise provided by Act of Congress, the district courts shall have original jurisdiction of all civil actions, suits or proceedings commenced by the United States or by any agency or officer thereof expressly authorized to sue by Act of Congress. The court rejected the defendant’s claim that 33 U.S.C. §1319(b) and 33 U.S.C. §1344(s)(3) authorized only the EPA to sue for violations of the CWA, thereby limiting the jurisdiction conferred by 28 U.S.C. §1345. Those provisions provide that the EPA Secretary is the party vested with the authority to sue for alleged CWA violations. The court determined that there is a “strong presumption” against implied repeal of federal statutes, especially those granting jurisdiction to federal courts. In addition, the court determined that the defendant failed to show that the general grant of jurisdiction was irreconcilable with either of the statutes the defendant cited. Accordingly, the court determined that the defendant could be sued by the U.S. Department of Justice upon the mere recommendation of the COE and without a specific recommendation from the EPA alleging a CWA violation, and in a situation where the CWA did not determine any CWA jurisdiction and only the COE did. This finding was despite a 1979 Attorney General opinion No. 197 determining that the EPA and not the COE has the ultimate authority to construe what is a navigable WOTUS.
Ultimately, the parties negotiated a settlement. The settlement included $1,750,000 civil penalty. The land which the farmer’s acts occurred will be converted to a conservation reserve and a permanent easement will run with the land to bar any future disturbance. The settlement also specified that the farmer would spend $3,550,000 "to purchase vernal pool establishment, re-establishment, or rehabilitation credits from one or more COE-approved mitigation banks that serve the [applicable] area . . . .". The settlement also included other enforcement stipulations, including fines and the civil penalty for noncompliance. No comments on the settlement were received during the public comment period, after which the settlement was submitted to the court for approval. The court approved the settlement ad consent decree on the basis that it was fair, reasonable, properly negotiated and consistent with governing law. The court also determined that the settlement satisfied the goals of the CWA in that it permanently protected the Conservation Reserve (which contained between 75 and 139 acres of WOTUS); fixed damage caused by unauthorized discharges; applied a long-term pre-clearance injunction; required off-site compensatory mitigation and recouped a significant civil penalty. The case is United States v. Lapant, No. 2:16-CV-01498-KJM-DB, 2019 U.S. Dist. LEXIS 75309 (E.D. Cal. May 3, 2019). United States v. Lapant, No. 2:16-CV-01498-KJM-DB, 2019 U.S. Dist. LEXIS 93590 (E.D. Cal. Jun. 3, 2019).
The three cases summarized today further illustrate the various legal battles that involve farmers, ranchers and rural landowners. They also illustrate the need to legal counsel that is well-versed in agricultural issues. That’s what we are all about in the Rural Law Program at Washburn Law School – providing high-level training in agricultural legal and tax issues and then getting new graduates placed in rural areas to represent farmers and ranchers.
Monday, October 7, 2019
2013 marked the beginning of major law changes impacting estate planning. Those changes were continued and, in some instances, enhanced by the Tax Cuts and Jobs Act (TCJA) enacted in late 2017. In particular, the “applicable exclusion amount” was enhanced such that (for deaths in 2019) the associated credit offsets the first $11.4 million in taxable estate value (or taxable gifts). Consequently, the vast majority of estates are not impacted by the federal estate tax. The “stepped-up” basis rule was also retained. I.R.C. §1014. Under that rule, property included in the estate at death gets an income tax basis in the hands of the heirs equal to the property’s fair market value (known as “stepped-up” basis). Much estate planning now emphasis techniques to cause property inclusion in a decedent’s estate at death to get the basis increase.
What are the planning steps to achieve a basis increase? What about community property? These are the issues addressed in today’s post.
Basis “Step-Up” Considerations – First Things First
As noted above, under present law, the vast majority of estates do not face federal estate tax at death. Thus, obtaining a basis increase for assets included in the gross estate is typically viewed as more important. Consequently, an initial estate planning step often involves a comparison of the potential transfer tax costs with the income tax savings that would arise from a “step-up” in basis. Unfortunately, this is not a precise science because the applicable exclusion adjusts be for inflation or deflation and could change dramatically depending on the whim of politicians.
It’s also important to note that a basis increase is of no tax help to the owner of the property that dies. The only way to capture the income tax benefits of the stepped-up basis adjustment is for the recipients of those assets to dispose of them in a taxable transaction. The degree of the benefit is tied to the asset. Farm and ranch land may never be sold or may only be sold in the very distant future. A basis adjustment at death is also beneficial if the asset involved is depreciable or subject to depletion. An additional consideration is whether the asset involved is an interest in a pass-through entity such as a partnership or an S corporation.
Exceptions To “Stepped-Up” Basis
There are exceptions to the general rule of date- of-death basis. For example, if the estate executor elects alternate valuation under I.R.C. §2032, basis is established as of the alternate valuation date (typically six months after death). Also, if the estate executor elects special use valuation under I.R.C. §2032A, the lower agricultural use value of the elected property as reported on the federal estate tax return establishes the basis in the hands of the heirs. For deaths in 2019, the maximum statutory value reduction for elected land is $1,160,000.
In addition, for land subject to a qualified conservation easement that is excluded from the gross estate under I.R.C. §2031(c), a “carryover” basis applies to the property. Also not receiving a basis increase at death is property that constitutes income in respect of a decedent (such as unrecognized interest on U.S. savings bonds, accounts receivable for cash basis taxpayers, qualified retirement plan assets, and IRAs, among other things). There’s also a special basis rule that involves appreciated property that was gifted to the decedent within one year of death, where the decedent transferred the property back to the original donor of such property (or the spouse of the donor). The donor receiving the property back will take as a basis the basis that the decedent had in the property immediately before the date of death. I.R.C. §1014(e). The property basis won’t step-up to fair market value at the date of the decedent’s death.
Community Property Considerations
The advantage of community property. On the basis step-up issue, estates of persons living in community property states have an advantage over estates of persons domiciled in separate (common law) property states. Under community property law, all assets acquired during marriage by either spouse, except gifts, inheritances, and assets acquired with separate property, are considered to be owned equally by the spouses in undivided interests. The title of an asset is not definitive in terms of ownership in community property states like it is in common law states. The community property states are Arizona, California, Idaho, Louisiana, Nevada, New Mexico, Texas, Washington and Wisconsin.
The ownership portion of the couple’s community property that is attributable to the surviving spouse by virtue of I.R.C. §1014(b)(6) gets a new basis when the first spouse dies if at least one-half of the community property is included in the decedent’s estate for federal estate tax purposes. This became the rule for deaths after 1947. Restated differently, there is a basis adjustment of both the decedent’s and surviving spouse’s one-half of community property at death if at least one-half of the community property was included in the decedent’s gross estate under the federal estate tax rules – which would normally be the result. The federal tax law considers the surviving spouse’s share to have come from the decedent. The result is a 100 percent step-up in the basis of the property. Conversely, in a common law property state, property that one spouse owns outright at death along with only 50 percent of jointly owned property is included in the estate of the first spouse to die (and receives a basis adjustment) unless the rule of Gallenstein v. Comr., 975 F.2d 286 (6th Cir. 1992) applies to provide a 100 percent basis step-up for property acquired before 1977.
Community property spousal trusts. Three common law property states, Alaska, South Dakota and Tennessee, authorize the creation of “community property trusts” for married couples that establish via the trust an elective community property system. See, Alaska Stat. Ann. §34.77.100; Tenn. Code Ann. Ch. 35-17-101 – 35-17-108; S.D. Cod. Laws. Ch. 55-17-1 – 55-17-14. In these states, married couples can classify property as community property by transferring the property to a qualifying trust.
Under the Alaska provision (enacted in 1998), at least one trustee must be an individual who resides in Alaska or a trust company or bank with its principal place of business in Alaska. The trust is irrevocable unless it provides for amendment or revocation. Certain disclosures must be made for the trust to be valid, and the trust must contain specific language declaring that the property contained in the trust is to be community property. Resident married couples can also execute an agreement to create community property for property that is not held in trust.
The Tennessee provision was enacted in 2010 and allows married couples to convert their property to community property by means of a “Community Property Trust.” Again, the idea of the trust is to achieve a 100 percent basis step-up for all of the trust property at the death of the first spouse. Comparable to the Alaska provision, at least one trustee must be an individual that resides in Tennessee or a company that is authorized to act as a fiduciary in Tennessee.
Under the South Dakota law (enacted in 2016), property contained in “South Dakota Spousal Trust” is considered to be community property even if one spouse contributed more than 50 percent of the property to the trust. At least one trustee must be a South Dakota resident, which could be one of the spouses. S.D. Cod. Laws §§55-17-1; 55-3-41. The trust must state that the trust property is intended to be community property and must specify that South Dakota law applies. S.D. Cod. Laws §55-17-3. Both spouses must sign the trust. S.D. Cod. Laws §55-17-1. Nonresidents can also utilize such a trust if a trustee is a qualified person that resides in South Dakota. In addition, significant disclosures are required between the spouses and both must consent and execute the trust. S.D. Cod. Laws §§55-17-11; 55-17-12. The trust can be either revocable or irrevocable if the trust language allows for amendment or revocation. S.D. Cod. Laws. §55-17-4.
Transfer of farmland. Can farmland that is owned in joint-tenancy, tenancy-by-the-entirety, or co-tenancy in a common law property state be transferred to a Community Property Trust created under the laws of these states and be treated as community property in order to achieve a full stepped-up basis at the death of the first spouse? Normally the law of “situs” (e.g. the location of where land is located) governs the legal status of the land transferred to a trust that is administered in another state. Neither the Alaska, South Dakota, nor Tennessee laws clearly address the legal nature of farmland that is transferred to such a trust from a common law property state, and there appears to be no caselaw or IRS rulings that address the question. Thus, a preferable planning approach might be to transfer the out-of-state farmland to an entity such as a limited liability company or family limited partnership followed by a transfer of the interests in the entity to the trust. Perhaps doing so would avoid questions concerning the property law and income tax basis issues associated with the out-of-state farmland.
The UDCPRDA. Presently, sixteen states (Alaska; Arkansas; Colorado; Connecticut; Florida; Hawaii; Kentucky; Michigan; Minnesota; Montana; New York; North Carolina; Oregon; Utah; Virginia and Wyoming) have enacted the Uniform Disposition of Community Property Rights at Death Act (“UDCPRDA”). The UDCPRDA specifies how property that was acquired while the spouses resided in a community property state passes at death if the spouses then reside in a common law property state. The UDCPRDA preserves the community property nature of the property, unless the couple has taken some action to sever community property rights. It does so by specifying that upon the death of the first spouse, one-half of the community property is considered the property of the surviving spouse and the other half is considered to belong to the deceased spouse. This should achieve a full basis step-up due to the unlimited marital deduction of I.R.C. §2056, however there aren’t any cases or IRS rulings on the impact of the UDCPRDA on basis step-up under I.R.C. §1014(b)(6).
The disparate treatment of community and common law property under I.R.C. §1014 has incentivized estate planners to come up with techniques designed to achieve a basis “step up” for the surviving spouse’s common law property at the death of the first spouse.
One way to achieve the basis increase is to give each spouse a power of appointment over the other spouse’s property which causes, on the death of the first spouse, the deceased’s spouse’s property to be included in the decedent’s estate by virtue of I.R.C. §2033 (if owned outright) and I.R.C.§2038 if owned in a revocable trust. The surviving spouse’s property would also be included in the decedent’s estate by virtue of I.R.C. §2041. The power held by the first spouse to die terminates upon the first spouse’s death and would be deemed to have passed at that time to the surviving spouse.
Another technique involves the use of a joint exempt step-up trust (JEST). In essence, both spouses contribute their property to the JEST that holds the assets as a common fund for the benefit of both spouses. Either spouse may terminate the trust while both are living, with the result that the trustee distributes half of the assets back to each spouse. If there is no termination, the joint trust becomes irrevocable upon the first spouse’s death. Upon the first spouse’s death, all assets are included in that spouse’s estate. Upon the first spouse’s death, assets equal in value to the first spouse’s unused exclusion will be used to fund a bypass trust for the benefit of the surviving spouse and descendants. These assets will receive a stepped-up basis and will not be included in the surviving spouse’s estate. Any asset in excess of the funding of the bypass trust will go into an electing qualified terminable interest property (QTIP) trust under I.R.C. §2056(b)(7). If the first spouse’s share of the trust is less than the available exclusion, then the surviving spouse’s share will be used to fund a bypass credit shelter trust. These assets will avoid estate taxation at the surviving spouse’s death.
The JEST technique comes with caution. Because the surviving spouse (the donor) could revoke the joint revocable living trust at any time, the surviving spouse arguably has dominion and control over the trust assets during the year before and up to the time of the decedent spouse’s death. That could mean that I.R.C. §1014(e) applies to disallow a basis increase in the surviving spouse’s one-half interest in the trust due to retained control over the trust assets within a year of death. See, Priv. Ltr. Ruls. 9308002 (Nov. 16, 1992) and 200101021 (Oct. 2, 2000).
For the vast majority of people, avoiding federal estate tax at death is not a concern. Some states, however, do tax transfers at death and the exemption in those states is often much lower than the federal exemption. But, achieving an income tax basis at death is of primary importance to many people. Community property has an advantage on this point, and other planning steps might be available to receive a full basis step-up at death. In any event, estate and income tax basis planning is a complex process for many people, especially those with farms and ranches and other small businesses that are trying to make a successful transition to the next generation. Competent legal and tax counsel is a must.
Wednesday, October 2, 2019
Court cases are many in which the IRS has asserted that the taxpayer is engaged in an activity without an intent to make a profit. If the IRS prevails in its claim that the taxpayer’s activity is a hobby, deductions for losses from the activity are severely limited. The tax result is even harsher as a result of the Tax Cuts and Jobs Act (TCJA).
What does it take to be conducting an activity with a profit intent? How did the TCJA change the impact of the “hobby loss” rules? These are the topics of today’s blog post.
Tax Code Rules
What is a “hobby”? A “hobby” under the Code is defined in terms of what it is not. I.R.C. §183. A hobby activity is essentially defined as any activity that a taxpayer conducts other than those for which deductions are allowed for expenses incurred in carrying on a trade or business or producing income. I.R.C. §§162; 212. The determination of whether any particular activity is a hobby activity or not is based on the facts and circumstances of each situation. It’s a highly subjective determination. But the Code provides a safe harbor. I.R.C. §183(d). Under the safe harbor, an activity that doesn’t involve horse racing, breeding or showing must show a profit for three of the last five years, ending with the tax year in question. It’s two out of the last seven years for horse-related activities. If the safe harbor is satisfied (either for horse activities or other activities, a presumption arises that the activity is not a hobby. The safe harbor applies only for the third (or second) profitable year and all subsequent years within a five-year (or seven-year) safe-harbor period that begins with the first profitable year. Treas. Reg. §1.183-1(c).
The burden of proof. Satisfaction of the safe harbor shifts the burden to prove that the activity is a hobby (i.e., lacks a profit motive) to the IRS. But the IRS can rebut the for-profit presumption even if the safe harbor is satisfied – although it doesn’t tend to do so without extenuating circumstances.
What about losses in early years? As noted above, the safe harbor applies only after a taxpayer incurs a third profitable year within the five-year testing period. That means that only loss years arising after that time (and within the five-year period) are protected. Losses incurred in the first several years are not protected under the safe harbor. It makes no difference whether the activity turns a profit in later years.
Postponing the safe harbor. It is possible to postpone the application of the safe harbor until the close of the fourth tax year (or sixth (for horse activities) after the tax year the activity begins. I.R.C. §183(e). This is accomplished by making an election via Form 5213 to allow losses incurred during the five-year period to be reported on Schedule C. Thus, if the activity shows a profit for three or more of the five years, the activity is presumed to not be a hobby for the full five-year period. The downside risk of the election occurs if the taxpayer fails to show a profit for at least three of the five years. If that happens, a major tax deficiency could occur for all of the years involved. Thus, filing Form 5213 should not be made without thoughtful consideration. For example, while the election provides more time to establish that an activity is conducted with a profit intent, it will also put the IRS on notice that an activity may be conducted without a profit intent. It also extends the statute of limitations for a tax deficiency (and refund claims) associated with the activity. See, e.g., Wadlow v. Comr., 112 T.C. 247 (1999).
Showing a Profit Intent – Some Recent Cases
While the IRS is presently not aggressively auditing many returns involving farm-related activities, the hobby loss area involving ag activities is one of them. So, what does it take to establish the necessary profit intent? Some recent court decisions provide guidance.
Cattle ranching activity deemed to be a hobby. In Williams v. Comr., T.C. Memo. 2018-48, the petitioner grew up on the family ranch in the Texas panhandle. He then went on to have a career as a chiropractor. He also operated a publishing and research business and a gun shop. He sold his chiropractic practice and bought an 1,100-acre ranch in south-central Texas. He ran a feeder-stocker cattle operation on the ranch, employing two ranch workers to tend to the cattle. The petitioner also hired a bookkeeper to manage his various business activities and a CPA to do the tax work for his businesses. He put approximately six to eight hours a week into the cattle ranching activity, and also spent time in his other business ventures. He modified his cattle operation after encountering problems that were detrimental to the viability of the business. The petitioner’s publishing business showed an average profit of approximately $300,000 each year; the gun shop was approximately a break-even business; and the cattle business averaged Schedule F losses of about $100,000 annually over a 15-year period, never showing a profit in any year (although losses declined on average over time).
The IRS examined years 2011 and 2012 and disallowed the loss from the ranching activity on the basis that the petitioner did not engage in the activity with a profit intent. The Tax Court analyzed each of the nine factors under Treas. Reg. §1.183-2. Of the nine factors contained therein, only one favored the petitioner - he did not derive any personal pleasure from the cattle ranching activity. The Tax Court determined that the petitioner did not operate the ranch in a businesslike manner; had no formal education in animal husbandry; did not view the hours spent in the activity by the employees as attributable to the petitioner; did not have a reasonable expectation of appreciation of the value of the ranch’s assets (but the Tax Court ignored the building improvements and fences that were built); had no history of running comparable businesses profitably; and had substantial income from other sources that the losses from the ranching activity offset.
Horse activity was a hobby. In Sapoznik v. Comr., T.C. Memo. 2019-77, the petitioners bought a horse in 2011 and participated in horse shows in 2014 and 2015. The horse was top-ten in its class nationally, and the petitioners hoped to be able to sell the horse for more than its purchase price. However, the lost more than $100,000 and sold the horse for what they paid for it. The petitioners deducted the $100,000 loss and the IRS rejected the deduction and assessed a penalty exceeding $6,000. The Tax Court agreed with the IRS that the activity was a hobby. The Tax Court noted that the petitioners had not conducted the activity in a businesslike manner. They also had no written business plan and didn’t keep accurate books and records. They also made no changes in how they conducted the activity to reduce expenses or generate additional income, and they did not attempt to educate themselves on how to conduct the activity. They also did not rely on the activity as a major source of their income, and never came close to making a profit.
Profit was “too gone for too long.” In Donoghue, et ux. v. Comr., T.C. Memo. 2019-71, the petitioners, sustained losses in their horse breeding/racing activity for almost 30 years without ever showing a profit. The husband was a computer programmer and his wife a retired paralegal and business executive. The wife had been a life-long horse enthusiast. They operated the activity via a partnership as a “virtual farm.” The IRS denied the loss deductions from the activity and the Tax Court agreed on the basis that the petitioners couldn’t satisfy the requirements of the regulations under I.R.C. §183. The Tax Court noted that the evidence clearly established that the petitioners didn’t operate the activity in a businesslike manner. They didn’t breed, race or sell any of their horses during the years at issue. While they had separate bank accounts and some records, the records were incomplete or inaccurate. While the petitioners had written business plans, the plans projected net losses and remained essentially unchanged from the original plans 30 years earlier. Also, their long string of unbroken losses was used to offset non-farm income, and the petitioners derived substantial personal pleasure from the activity. They left the “grueling aspects” of the activity to others that they paid, and there was no evidence that they sought expert advice concerning how to make a profit at the activity. Instead, they sought only general advice.
Golf course activity conducted for profit. In one recent non-ag case, WP Realty, LLP v. Comr., T.C. Memo. 2019-120, a profit intent was found to be present. The petitioner, a limited partnership, owned and operated a golf course. The limited partner and sole shareholder of the general partner was a real estate developer and developer of golf courses who created a nonprofit corporation to which he planned to donate the golf course at issue. The IRS approval of nonprofit status was conditioned on the corporation focusing only on charitable activities and distributing funds to a medical center. As a result, the golf course gave access to the corporation and members. The corporation paid rent and members paid fees for golf rounds. The golf course was managed by an experienced manager. The manager kept complete books and records and maintained budgets for the course and facilities. Between 2001 and 2015, the golf course sustained losses which flowed through the petitioner to the limited partner. The golf course reported a net profit in 2016.
The IRS denied the loss deductions on the basis that the golf course was not engaged in its activity for profit. The Tax Court disagreed based on the nine factors of Treas. Reg. §1.183-2(b), a predominance of which favored the petitioner. The golf course was operated in a businesslike manner with complete and accurate books and records, and the records were used to determine when capital improvements should be made. Steps were also taken to make the golf course more profitable. In addition, the managers had extensive experience in the golf industry and in managing golf clubs. The Tax Court also noted that the limited partner had successfully developed two other golf clubs and did not derive substantial tax benefits from the passed-through losses. While a long history of losses was present, that factor was not enough to negate the petitioner’s actual and honest intent to make a profit.
The TCJA suspends miscellaneous itemized deductions for years 2018-2025. Thus, deductions for expenses from an activity that is determined to be a hobby are not allowed in any amount for that timeframe. I.R.C. §67(g). But all of the income from the activity must be recognized in adjusted gross income. That’s painful, and it points out the importance of establishing the requisite profit intent.
Hobby activities involving agricultural activities (especially those involving horses) have been on the IRS radar for quite some time. That’s not expected to change. It’s also an issue that some states are rather aggressive in policing. See, e.g., Howard v. Department of Revenue, No. TC-MD 160377R, 2018 Ore. Tax LEXIS 35 (Ore. Tax Ct. Mar. 16, 2018); Feola v. Oregon Department of Revenue, No. TC-MD 160081N, 2018 Ore. Tax. LEXIS 48 (Ore. Tax. Ct. Mar. 27, 2018). It’s also not an issue that the U.S. Supreme Court is likely to review if the taxpayer receives an unfavorable opinion at the U.S. Circuit Court of Appeals level. See, e.g., Hylton v. Comr., T.C. Memo. 2016-234, aff’d., No. 17-1776, 2018 U.S. App. LEXIS 35001 (4th Cir. 2018), cert. den., No. 18-789, 2019 U.S. LEXIS 966 (U.S. Sup. Ct. Feb. 19, 2019).
Tuesday, October 1, 2019
When one thinks of estate planning, visions of wills and/or trusts come to mind and maybe even a power of attorney for financial and health care decisions. Those are the standard documents. If a spouse is also involved in the process, then the coordination of the language in the documents for each spouse is also critical to ensure that the couple’s property passes as desired after the last of them dies.
But, beyond the basic documents and coordinated planning, there are numerous legal issues that can arise. Those can include issues associated with someone else acting on one’s behalf; promises to pass property at death; and the process for replacing a trustee of a trust. Some recent court cases dive into each of these issues.
Legal issues arising during the estate planning process – it’s the topic of today’s post.
Signing Documents On Behalf Of Someone Else
In In re Estate of Moore, No. 115,628, 2019 Kan. LEXIS 321 (Kan. Sup. Ct. Sept. 6, 2019), the decedent appointed the defendant (her ex-daughter in law) as her power of attorney. The plaintiff (the decedent’s son) had a long history of poor financial decisions, including losing 440 acres that the decedent pledged as security for him. More than $100,000 of the decedent’s money was lent or just straight up taken out of her accounts by the plaintiff. An attorney was hired to keep the plaintiff from obtaining the decedent’s “homeplace.” A transfer on death deed was created to move the property to the defendant so that it could later be transferred to the decedent’s grandsons (the children of both parties).
In May of 2004 the deed was read to the decedent, and the legal description was double checked. One of the grandsons asked if that decedent wanted them to have the property, which she answered “yes.” In the presence of five witnesses the decedent asked the defendant to sign for her. The deed was notarized and filed. The decedent died on September 15, 2009. On November 7, 2012, the defendant executed a warranty deed conveying the homeplace to the grandsons. In 2014 the plaintiff filed petition for determination of descent asserting that the homeplace should have been in the estate. The grandsons countered that the property passed to them by transfer on death deed and was not in the estate.
The trial court initially found for the plaintiff based on the fact that the defendant could not benefit herself with that right. The defendant filed a motion to reconsider and claimed that the she did not sign the deed with her power of attorney but as an amanuensis – at the direction or dictation of someone else. The trial court agreed as did the appellate court. On further review, the state Supreme Court also agreed. The plaintiff challenged the validity of the signature by amanuensis noting that the defendant signed the transfer on death for the decedent and the added "by Maureen Miles, Power of Atty." The Supreme Court noted that state (KS) common law recognizes as valid a signature made by a person at the direction of someone else. The Court noted that the evidence was clear that the deed was properly signed by amanuensis. There were six witnesses that testified that the decedent asked the defendant to sign the deed for her. The plaintiff failed to present evidence to the contrary. The Court also rejected the plaintiff’s claim that the signature was not properly acknowledged. The deed was notarized after the defendant signed it for the decedent. The notary attached a notation indicating this intricacy. The deed was filed 3 days later. The deed conformed to state law by being signed; designating a beneficiary; acknowledged by a notary; and recorded in the office of the register of deeds prior to the decedent’s death. The Court found the deed signed by amanuensis to be proper even though the notary acknowledged the defendant’s power of attorney. The Court also rejected the plaintiff’s undue influence claim by concluding that the plaintiff failed to rebut the presumption that the decedent was competent in accordance with the general competency test for testamentary capacity. The decedent had strong motivations to ensure that the plaintiff did not receive her property, and the defendant transferred the property to the decedent’s grandsons before the litigation and did not benefit from the transaction.
In a recent Idaho Supreme Court decision, Turcott v. Estate of Bates, 443 P.3d 197 (Idaho 2019), the Court dealt with the legal force of an apparent promise not to change a will before death. Under the facts of the case, in the late 1990’s the decedent executed a will devising the decedent’s farm to the decedent’s daughter and son equally. From 2007 until 2014 the daughter and her husband moved to the farm. They built a home on the farm and spent a lot of time and money maintaining the farm. In 2014, the decedent remarried and revoked the will. The decedent then placed the farm in a trust listing his new wife and himself as beneficiaries. The new will stated, "I purposefully have excluded my daughter as a devisee of my estate and my daughter shall take nothing from my estate." In 2016, the daughter sought to enforce the validity of the first will based on a promise that the will would not be changed or revoked before death. The trial court dismissed the plaintiff’s claim for the alleged promise to maintain the will. The plaintiff then filed an amended petitioner seeking quantum meruit damages for the work the plaintiff performed on the farm. The trial court awarded the plaintiff $136,402.50 in damages for unjust enrichment, but the plaintiff appealed on the basis that the amount was too low. On further review, the appellate court affirmed and did not award attorney fees because the appeal was not frivolous.
How Long Does a Trustee Serve?
In Waldron v. Suasan R. Winking Trust, No. 12-18-00026-CV, 2019 Tex. App. LEXIS 5867 (Tex. Ct. App. Jul. 10, 2019), the plaintiff was the beneficiary of a trust that her parents created. The appointed trustee of the trust resigned and the appointed successor trustee (a bank) refused to serve as trustee. The trust instrument specified that if the successor trustee failed to serve that any bank or trust company could be appointed trustee by the serving of written notice signed by the grantor. However, the plaintiff could not find a bank or trust company willing to serve as trustee, so the plaintiff filed an action seeking to have an individual appointed as trustee. The trial court made such an appointment.
The plaintiff later filed an action to be appointed trustee due to improper conduct of the individual that had been appointed as trustee. That individual did not object to being removed as trustee upon appointment of another qualified trustee. The plaintiff subsequently sought to have another person appointed as trustee. This eventually happened, but the plaintiff asserted that the trial court ignored the trust language allowing for immediate termination of the trustee without cause by written letter if both grantors were legally disabled or deceased. Immediate termination would have saved the plaintiff from paying additional expenses for professional serviced. The appellate court noted that the trust language did not provide a procedure for appointing a successor trustee when a bank or trust company could not be found to serve. Thus state (TX) law applied and left the decision of a successor trustee up to the court. State law also specified that an existing trustee’s fiduciary duties were not discharged until the trustee had been replaced by a successor trustee. As a result, the appellate court affirmed the trial court’s decision.
Estate planning is a complex process in many situations. Precision of drafting language is critical, but it depends on client clarity as to goals and objectives and attention to changes in applicable law. Even then, however, landmines may still exist. This is why “boilerplate” language and “boilerplate” forms printed off the web can be dangerous to use. Get and keep good estate planning counsel.