ASPECTS OF TAX BENEFITS OF TEXAS JOINT VENTURE PROGRAMS
The new
venture may set up each new oil and gas well program as Texas Tax Partnership
which is governed by the Texas Revised Partnership Act (Texas RPA) and by a
Joint Venture Agreement (JVA). The Venture shall have the status of a general
partnership and each Venturer shall have the status as a general partner. The
JVA names the entity which syndicates the Venture as the Managing Venturer and
is executed with each Venturer. The tax status, although not ruled upon by the
IRS, will be filed as a tax partnership by preparation and filing of an S-4
with the IRS for federal income tax purposes. A partnership tax return will
be prepared each tax year for the Venture and partners on Form 1065 and a K-1
will be issued to each partner for their share of revenue and expenses and tax
preference items and the reporting of their partnership accounts.
The joint
venture enters into two types of contracts with the Operating Company:
1.
A Turnkey Drilling Contract to pay for the organizational
costs required in setting up the Venture and to pay for the drill and testing
costs of one prospect well. Upon recommendation by the operator to complete
and a majority vote, a second contract is entered into by the Venture.
2.
A Turnkey Completion Contract to pay for any additional
general and administrative and organization costs and to pay for the costs of
completing the well to the point it is capable of production.
Although the purpose of the Venture is for economic benefit, there are
favorable federal income tax aspects afforded to each participant in these
programs. Each program memorandum outlines the risks and rewards
associated with each Venture and the related tax aspects and appropriate
disclaimers necessary to adequately inform these sophisticated investors. The
following provides you with a detailed explanation of these tax items, their
benefits and the tax treatment by the partnership, which is important to keep
in mind when discussing our programs to these qualified investors.
Keep in mind Arcturus Corporation never represents this information as tax
advice but as information necessary for our investors to make an informed
decision and for them to seek their own tax advice from their tax advisor or
CPA.
I.
Drill & Test Phase
Funds
Raised during this phase cover two (2) types of costs:
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Program Costs
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Organization and Business Startup Costs
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General & Administrative Costs
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Syndication Costs
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Project Costs
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Leasehold and Prospect Costs
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Geological & Geophysical Costs
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Intangible Drilling Costs
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Tangible Equipment Costs
1.
Organization Costs and Business Set Up Costs
Organization Costs shall mean the aggregate of:
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Attorneys’ and accountants’ fees
in connection with the organization and formation of the Venture and
the preparation of the Memorandum and/or collection of the assessments.
Legal fees for services incident to the organization of the partnership,
such as negotiation and preparation of the partnership agreement
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All other expenses in connection with
formation incurred by the Venture or Managing Venturer, including
processing the applications for participation in the Venture and
collection of assessments. Filing Fees or costs incurred with State
agencies or IRS to register the partnership entity.
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Tax Treatment prior to October 23, 2004:
The Tax Reform Act of 1976 added Section 709 to the Internal
Revenue Code which precludes a deduction, in years beginning after December
31, 1975 for amounts paid or incurred to organize a partnership or promote
the sale of (or to sell) an interest in such partnership. However,
amounts paid or incurred after December 31, 1976 to organize a partnership
(as distinguished from promoting or selling an interest therein) may be
amortized over a period of not less than 60 months. If the partnership is
liquidated within the amortization period, the unamortized portion will be
deducted as an expense under section 165 of the Code. This regulation now
only applies to costs incurred prior to October 23, 2004.
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Tax Treatment October 23, 2004 and After:
Organization costs incurred and paid for partnerships (cash basis
taxpayer), these costs under Section 709 can be expensed up to $5,000
in the year incurred and paid. All costs over that amount must be amortized
over 180-month period. The amortization period starts with the month you
begin business operations. Business Start up costs incurred and paid for
partnerships (cash basis taxpayer), these costs under Section 195 can be
expensed up to $5,000 in the year incurred and paid. All costs over that
amount must be amortized over 180-month period. The amortization period
starts with the month you begin business operations. The amortization start
period may be different than that for organization costs but must be for a
180-month period also. The tax payer (partnership) should attach a
statement required by the appropriate Code section and related regulations.
If both are claimed, separate statements are required for each cost.
2.
General and Administrative Costs (G&A) General &
Administrative Costs of the Managing Venture during the capitalization
period directly associated with the organization and formation of the
Venture. General & Administrative Costs of the Managing Venture
during the capitalization period directly associated with the organization and
formation of the Venture.
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Allocable salaries and expenses of
employees of the Managing Venture assisting with organization and
formation of the Venture and/or collection of assessments;
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Expenses for printing and mailing
material used in connection with the applications for
participation in the Venture and/or collection of assessment.
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Bank Escrow Account and service fees
paid in connection with maintaining Venture deposits and safeguarding
partnership funds prior to disbursement of funds for drill and tests or
completion operations. On going bank fees for Venture Operating Accounts
used to joint venture cash receipts and disbursements.
3.
Syndication Costs- Syndication Costs are the costs
for issuing and marketing interests in the partnership such as brokerage,
registration, and legal and printing costs. These syndication fees are
capital expenses and cannot be depreciated or amortized.
4.
Intangible Drilling Costs (IDC)
The regulations define intangibles as any cost incurred than in itself
has no salvage value and is incident and necessary for the drilling of wells
and the preparation of wells for the production of oil and gas.
This definition includes the cost of installation of tangible equipment placed
in the well itself although the equipment is to be capitalized and
depreciated. Intangible Drilling Costs include:
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Costs of agreements and negotiations in
obtaining operator of the well.
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Costs incurred for agreements and
negotiations with drilling contractors as to bids for drilling.
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Survey and seismic work as to location of
well site.
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Costs of road to location to be used during
drilling.
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Costs of dirt work on location, cellar, pits,
and drilling pack.
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Costs of transporting rig to location, and
rig-up costs.
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Costs incurred for water, fuel and other
items necessary for drilling the well.
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Costs of setting deadmen (anchors in the
ground used to stabilize drilling rig).
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Drilling costs calculated on footage or
day-rate basis.
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Costs of technical services rendered during
the drilling activities by engineers, geologists, fluid technicians, etc.
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Costs of logging and drill-stem test
services.
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Costs of swabbing, fracturing, and acidizing.
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Costs of rental equipment for oil storage
during testing.
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Costs of removing rig from location, trucking
dozers, and labor
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Dirt work and clean-up of drill site.
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Cementing and installation of surface casing.
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Cementing of main casing.
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Transportation of casing and tubing from
supply point.
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Perforation of casing, including electrical
logging.
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Salt water, fresh water, and gas injection
wells drilled solely for pressurization or flooding of producing zone.
Expressly excluded from classification as intangibles are expenses, including
installation charges, incurred for equipment, facilities, or structures that
are not incident to the drilling of the well, such as structures for storing
and treating oil or gas. (Section 1612-4 of the Code.) These costs are
installation costs and are capitalized as part of those structures and
recovered through tangible equipment depreciation.
Any taxpayer (investor) who owns the operating rights in an oil or gas
property and incurs intangible costs must elect to expense or to capitalize
these costs. (Rev. Rul. 67-34, 1967-1 CB 72.) Although the Tax Reform Act
of 1986 provides uniform rules for the capitalization of costs incurred
regarding property used in production, intangible drilling costs are excluded
from the capitalization rules (IRC, Section 263A). The election must be made
by the tax payer (investor) for his first tax year in which intangibles are
incurred. Once made, the election is binding on the taxpayer (investor) for
all later years (IRC 1612-4). Each partner in a tax partnership is required
to make their own election.
If the taxpayer elects to capitalize the intangible costs, an allocation must
be made and the costs must be recovered (1) through depletion to the extent
the costs are not represented by physical property or (2) through depreciation
to the extent the costs are represented by physical property.
In making the election to expense intangibles, investors must consider that
intangibles on productive wells incurred after December 31, 1975 (for
non-corporate tax payers may be subject to the Alternative Minimum Tax. In
addition, investors must be aware of the impact of potential recapture of
intangibles, if they sell or otherwise make a disposition of their interest in
the future.
If the investor wants to expense intangibles, an express statement should be
included with their return that the investor elects to deduct intangibles in
accordance with the option granted by Regulation Section 1.612-4 (a).
Election to Expense
Under the general rules, if an investor has properly elected to deduct
(expense) intangible drilling costs, the time for the deduction is the tax
year in which the costs are incurred, by an “accrual-basis” tax payer, or in
which such costs are paid, by a “cash-basis” tax payer. In Revenue Ruling
71-252, the IRS ruled that IDC paid under a contract (i.e. Turnkey Drilling
Contracts) by a cash-basis taxpayer who had elected in a prior year to treat
such costs as expenses, are deductible in the year paid even though the work
is performed in the following year. For tax years beginning after December
31, 1986 under the Tax Reform Act of 1986, economic performance must have
occurred before prepayments can be deducted. For tax years beginning after
December 31, 1986, economic performance is deemed to have occurred, if the
drilling of the oil or gas well begins within 90 days of the close of the tax
shelter’s tax year. (IRC, Section 461 (i)(2) as amended by Section 801(b)).
For our investors, the well must be spudded by the 90th day of the
year.
Election to Capitalize
If an investor elects to capitalize IDC, the regulations require that expenses
not represented by physical property, such as clearing ground, draining, road
making, surveying, geological work, excavating, grading, and the drilling,
shooting, and cleaning of wells, be capitalized and recovered through cost
depletion. Expenses represented by physical properties, including wages,
fuel, repairs, hauling, supplies, and so on, used in the installation of
casing and equipment when intangibles are capitalized, are to be recovered
through depreciation.
However, a taxpayer may elect to annually capitalize these costs and deduct
them over a 60 month period, beginning in the first month in which the
expenditures were paid or incurred. Capitalization of Intangible Drilling
Costs is rarely more beneficial to an investor than electing to expense such
costs, because statutory depletion does not require any basis in the property
while cost depletion does.
5.
Geological & Geophysical Costs (G&G)- G&G Expenses can be
amortized if paid or incurred in connection with the exploration and
production of oil and gas in the U.S. ratably over a 24-month for costs paid
or incurred after May 17, 2006. The amortization period begins on the
mid-point of the tax year in which the expenses were paid or incurred. This
election is made under section 167(h).
II.
Completion Phase
Funds
raised during this phase cover two types of costs:
1.
Organization Costs
b)
Organization Costs (additional organization costs necessary for
this phase)
These are the same types of costs defined above in the Drill & Test Phase and
will continue to be incurred and carry over into the Completion Phase of
drilling and as covered by the Turnkey Completion Contract.
b)
Tax Treatment: These costs will be amortized over 180
months as stated above under the Drill & Test Phase.
2.
Tangible Completion Costs (Tangible Equipment)
a)
What is Tangible Equipment?
Tangible Equipment is the physical equipment placed down-hole in the well and
the physical equipment placed on the surface for the well and lease. It
includes the direct costs to install, construct and placed the equipment in
working condition. The equipment includes two components:
·
Intangible Completion Costs (Installation Costs).
Installation charges, incurred for equipment, facilities, or structures that
are not incident to the drilling of the well, such as structures for storing
and treating oil or gas. (Section 1612-4 of the Code.) These costs are
installation costs and are capitalized as part of those structures. Note: IDC
includes the cost of installation of tangible equipment placed in the well
itself, although the equipment is to be capitalized.
·
Tangible Completion Costs (Physical materials and
equipment). Tangible well and lease equipment include the following:
o
Surface Casing (even though permanently cemented and
non-salvageable.
o
Well Casing.
o
Tubing.
o
Transportation of casing and tubing from manufacturer to supply
point.
o
Stabilizers, guide shoes, centralizers and down-hole equipment.
o
Wellhead (Christmas Tree)
o
Salt Water Disposal Equipment and necessary pipelines, including
cost of drilling well.
o
Water Tanks
o
Production Tanks
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Pump jack, Heater Treaters, Separators
o
Recycling equipment, including necessary flowlines.
o
Dirt moving necessary for tank battery and operation roads.
o
Digging, refilling, and backhoe work for installation of
flowlines from well to tank battery.
o
Installation and labor costs for tank battery, flowlines, pump
jacks, separators and other similar items.
o
Construction of turn-around pad at tank battery with additional
overflow pits.
·
It is important to distinguish between the two types of
installation costs: (1.) The costs of installing equipment necessary for the
drilling of the well and for the preparation of the well for production is
regarding as “intangible”, if the investor elects to expense IDC. The IRS
regards the well as complete when the casing and a “Christmas Tree” have been
installed. The cost of installing the equipment to this point, which would
include casing, tubing, the Christmas Tree, and other well facilities, is
considered intangible. If however, the taxpayer (investor) elects to
capitalize intangible costs, such costs become part of the equipment costs and
recovered through depreciation. (2.) The IRS considers pumping equipment,
flowlines, separators, storage tanks, treating equipment, salt water disposal
equipment, and so on, as production facilities, and costs incurred in their
installation must be capitalized as equipment costs. (Rev. Rule 70-414).
·
The inclusion of Intangible Completion Costs (installing
equipment placed in the well itself) as part of the Tangible Equipment depends
upon Election to Expense or Capitalize IDC by the investor. If the investor
elects to expense IDC, these costs are excluded from tangible equipment. If
the investor elects to capitalize IDC, these costs are included as part of the
tangible well costs and are capitalized and recovered through depreciation.
b)
Tangible Equipment Depreciation Expense
The cost of oil and gas property placed in service after 1980 is
recoverable under the Accelerated Cost Recovery System (ACRS).
ACRS uses statutory accelerated methods to recover the entire cost of the
property over periods of time fixed by the IRC (Internal Revenue Code
or “Code”). It makes no distinction between new and used property, and
disregards salvage value. The costs of depreciable personal
property is recoverable over a 3,5,7,10,15, or 20-year period, depending on
the type of property. (IRC, Section 168 (c) (1)) The class to which an asset
belong depends primarily on the midpoint of its class life under the ADR rules
(Rev Proc. 83-85, 1983-1 CB 745). ADR stands for Asset Depreciation Range.
Three-year property includes property with a four-year-or-less midpoint life
under the ADR system, other than cars, light-duty trucks, which are five
years. Five-year property consists of property with an ADR midpoint life of
more than four years and less than 10 years. The 7-year class includes: (1)
any property with an ADR midpoint of 10 years or more and less than 16 years
and (2) property with no ADR class life that is not assigned to another
class. Office furniture, fixtures, and equipment (including lease and
well equipment), that were previously in the 5-year class are now included in
the 7-year class. (IRC 168(e)(1) and (3) (C)).
c)
Tax Treatment:
Tangible Equipment Depreciation
The depreciation method for property in the 3,5,7 and 10-year classes is the
200 percent declining-balance method, with a switch to straight-line for the
first year in which the latter system will produce the larger deduction. The
depreciation method for 15- and 20-year property is 150 percent declining
method, also switching to straight-line to maximize the deduction. Most
of the equipment deployed on our wells will fall in the 7-year class life.
Based upon the property being placed in service for less than 12 months during
the first year, a mid-year convention is used. This results in a rate of
14.29% for the first year, 24,49% for the second year, 17.49% for the third
year, and 12.49% for the fourth year, 8.93% for the fifth year, 8.92% for the
sixth year and 4.46% for the seventh year. During the fourth year a switch to
straight-line method would be necessary. Finally, any depreciation
allowable on such tangible property and equipment is subject to recapture as
ordinary income if the investor’s interest or the property is disposed of
before the end of its class life. (IRC Section 167 (a)-8(e))
Election to Expense Depreciable Business Assets (Section 179
Expense)
A taxpayer (investor other than a trust or estate) can elect to treat some of
the cost of qualifying property as a currently deductible expense. Section
179 of the IRC allows you to elect to deduct all or part of the cost of
certain qualifying property (tangible personal property purchased for use in
business; i.e. tangible well and lease equipment). The taxpayer can elect to
expense rather than recover the cost through depreciation; however, there are
limits on the amount you can deduct in a year. For 2006, the dollar ceiling
on the amount that can be expensed is $108,000 for taxpayers whose total
investment in tangible personal property is less than $430,000. For every
dollar investment that exceeds $430,000, the dollar ceiling is reduced by one
dollar. (IRC, Sections 179(b) (1) and (2). The section 179 deduction limits
apply both to the partnership and to each partner. The partnership determines
its section 179 deduction subject to the limits. It then allocates the
deduction among its partners. Each partner adds the amount allocated from the
partnership (shown on Schedule K-1) to their non-partnership Section 179 costs
and then applies the maximum dollar limit to this total.
Production Phase
The
following types of revenues are earned. Depending on whether the investor is
a cash or accrual basis tax payer, revenue is recognized by the tax payer for
a tax year. On the joint venture partnership a partnership tax return is
filed and each investor will be issued a K-1 information return. In that
case, the partnership is a cash basis entity and revenue will be recognized in
the year paid.
o
What is depletion? Depletion for tax purposes:
Only the owner of an economic interest in a property (well) is entitled to
depletion on the income derived from production and sales of the minerals from
that property. The owners of mineral interests, royalties, working interests,
overriding royalties, net profits or production payment are all owners of
economic interests in the minerals. The owner of each property (well)
is entitled to depletion for Federal tax purposes. The Code provides two
methods of computing the depletion allowance: cost and percentage depletion.
(IRC, Section 611)
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Cost Depletion – Cost depletion
provides for a deduction of the taxpayer’s basis in mineral property in
relation to the production and sale of minerals. Cost depletion allows
the recovery of capitalized costs (such as bonus, other lease
acquisition costs, exploratory charges, legal fees and certain other
capitalized, non-depreciable costs commonly grouped and classified as
“leasehold costs”).
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Percentage Depletion- Percentage
depletion, on the other hand, is a statutory concept, which provides for
a deduction of specified percentages of the gross income from the
property but not to exceed the net income from the property. It can not
exceed 100% of the taxable income from the property before allowance for
depletion. Except for certain natural gas production, percentage
depletion is generally available only with respect to a limited amount
of domestic crude oil or domestic gas production of each taxpayer
(investor), under the so-called “independent producer exemption”. The
depletable oil quantity is limited to 1,000 barrels of crude oil
production per day, and the rate for percentage depletion is 15 percent.
(IRC, Section 613A ( c) (1) (b)). The depletion deduction under the
independent producer exemption may not exceed 65% of the taxpayer’s
taxable income for the year, without regard to certain deductions and
subject to a carryover of the unused portion of the deduction.
The taxpayer is not given an election to compute depletion one way or
the other, but must compute depletion both ways and claim the higher of the
two sums. Allowable depletion, which is the higher of cost or percentage
depletion, reduces the taxpayer’s basis in the mineral property. Allowable
depletion is not restricted to the taxpayer’s basis, however; although cost
depletion will be zero after the taxpayer’s basis has been fully recovered,
the investor may continue to claim percentage depletion based on income from
the property.
o
Tax Treatment: The percentage depletion for oil and gas
wells is 15% of the gross revenues before deducting cost of sales. IRC
Section 611 allows as a deduction a reasonable allowance against oil and gas
revenues. Depletion is a tax preference item and is passed through to each
partner similar to IDC. There are two limitations which must be taken into
consideration:
§
Net Income Limitation-Percentage depletion can not
exceed 100% of the taxable income from the property before the allowance for
depletion.
§
65% Tax Payer Income Limitation-Percentage depletion can
not exceed 65% of the taxpayer’s net income for the year.
Subsequent Operations Phase:
This phase
covers work outside of the scope of this discussion for discussion of tax
aspects of our Private Placement Memorandums. Such events are covered under
the Memorandum and the Joint Venture Operating Agreement. Such subsequent
operations l require special assessments when the Operator of the Venture and
the Venture votes to:
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Deepen or lengthen the Wellbore after reaching
the total measured depth as determined in the original target depth of the
venture;.
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Sidetrack the Wellbore if conditions or
situations are encountered which render further drilling impractical or
permits Driller/Operators to abandon the well;
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Plug back the Wellbore and attempt completion
in a new zone
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Conduct any activity for the purpose of
enhancing production or artificial fracture stimulation
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Install pumping equipment
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Install pipelines
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Install any type of gas treatment facilities or
production facilities;
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Completion any zones in addition to the first
completion; or
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Drilling of additional wells.
These sub
operations may result in Non-Consenting Partners being assessed penalties or
outright termination from the Venture. The tax treatment for these costs will
vary as to the nature and purpose of the subsequent operations.
