C H A P T E R

23

Glossary Terms
carried interests
arrangement
carried party
carrying party
equalizations
free well agreement
participation factors
reversionary interest

FARMOUTS,
CARRIED INTERESTS,
AND UNITIZATIONS
Key Concepts:
• Definition of the term farmout
• Carried interests
• Accounting for unitization
• Tax accounting for farmouts, carried interests, and
unitizations


Chapter 23

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388

The pooling of capital concept has long been a part of accounting theory as well as an
essential element in the federal taxation of extractive industries. It is common for an entity
to acquire an interest in a mineral property through the contribution of money, property,
or services, and assume all or part of the risk and burden of developing and operating
it. One party may contribute a leasehold to the venture, another may provide equipment
or services, such as drilling, and still another entity may contribute money. Members of
the venture agree that they are contributing to a common pool of capital. Thus, each is
viewed as making an investment in a venture or adding to the venture’s reservoir of capital
in return for ownership interest in the venture as a whole.
Many transactions of this type are also considered as exchanges of productive assets in
return for similar productive assets, especially if mineral interests, intangible drilling costs,
and equipment are viewed as similar. FASB Current Text Oi5.135 states no gain or loss
is recognized at the time of conveyance in a pooling of capital or an exchange of similar
productive assets.
Commonly encountered applications of these concepts are examined in this chapter.
Generally, it is assumed that the successful efforts method is being followed. Although
many of the same rules apply, special considerations for full cost companies are examined
at the end of this chapter.

FARMOUTS
When the owner of a working interest transfers all or part of the operating rights to another
party in exchange for the transferee assuming some portion of the cost of exploring or
developing the property, the transaction is referred to as a farmout. One type of farmout is
essentially a sublease without cash consideration. The original lessee assigns the working
interest, but retains an overriding royalty or a net profits interest in return for the assignee’s
agreement to perform and pay for specified drilling and development activities.
For example, assume ABC Oil Company (ABC) assigns the working interest in Nellie
Bell lease No. 26710 to Big Time Company, subject to a retained overriding royalty of
one-eighth of total production from the property. As consideration, Big Time agrees to
drill a well to a depth of 5,000 feet or to a specific sand formation, if shallower. Big Time

is to complete the well and bear all equipment installation costs. It spends $340,000
for intangible drilling and development costs and $80,000 for lease and well equipment.
ABC’s original lease cost was $75,000 and it had a fair value of $400,000 at the time of
the farmout agreement.
Oi5.138(b), specifies how this transaction should be accounted for by the two parties:
An assignment of the operating interest in an unproved property with retention of
a nonoperating interest in return for drilling, development, and operation by the
assignee is a pooling of assets in a joint undertaking for which the assignor shall
not recognize gain or loss. The assignor’s cost of the original interest shall become
the cost of the interest retained. The assignee shall account for all costs incurred as
specified by paragraphs .106 through .132 and shall allocate none of those costs to
the mineral interest acquired. If oil or gas is discovered, each party shall report its
share of reserves and production (refer to paragraphs .160 through .167).
In this instance, both entities have contributed to the pool of capital. Each has benefited,
yet no gain or loss is recognized by either party. ABC’s leasehold cost of $75,000 becomes
its cost for the overriding royalty retained and is recorded as follows:


Farmouts, Carried Interests, and Unitizations

389

223

Proved Royalties and Overriding Royalties
211

Chapter 23

75,000

75,000

Unproved Property Acquisition Costs

To record farmout of Nellie Bell lease and retention of one-eighth
override.

The entry assumes that no impairment of this property has been recorded on an individual
lease basis. If such an impairment occurs, the net book value of the lease is assigned to
the overriding royalty. For example, assume that individual impairment of $30,000 has
been recorded on the lease in the preceding example. The entry to record the farmout is:
223

Proved Royalties and Overriding Royalties

45,000

219

Allowance for Impairment and Amortization of Unproved Properties

30,000

211

75,000

Unproved Property Acquisition Costs

To record farmout of Nellie Bell lease and retention of one-eighth

override.

Big Time classifies its investment in the property based on the type of expenditures
made. No part of the costs incurred is allocated to the mineral rights obtained, and no gain
or loss is recorded. The entry made by Big Time is summarized as follows:
231

Intangible Costs of Wells and Development

340,000

233

Tangible Costs of Wells and Development

80,000

301

420,000

Vouchers Payable

To record the costs of drilling and equipping well on Nellie Bell lease
under a farmout agreement.

If the well is dry, the costs incurred (less net salvage) are charged to Unsuccessful Exploratory
Wells by Big Time. ABC would have recorded impairment of the overriding royalty.

FREE WELLS

When the owner of a working interest assigns a fractional share of the interest in return
for another operator’s drilling and equipping one or more wells without cost to the assignor,
a free well has resulted. The term free well is used because the assignor retains a portion
of the working interest and receives an interest in the well and equipment without bearing
any part of the cost. The assignor also shares in the first production from the well.
A free well is considered a sharing arrangement under the pooling of capital concept, and no
gain or loss is recognized by either party to the transaction. Oi5.138(c) addresses this issue:
An assignment of a part of an operating interest in an unproved property in exchange
for a “free well” with provision for joint ownership and operation is a pooling of assets
in a joint undertaking by the parties. The assignor shall record no cost for the obligatory
well; the assignee shall record no cost for the mineral interest acquired. All drilling,
development, and operating costs incurred by either party shall be accounted for as
provided in paragraphs .106 through .132. If the conveyance agreement requires the
assignee to incur geological or geophysical expenditures instead of, or in addition to,
a drilling obligation, those costs shall likewise be accounted for by the assignee as
provided in paragraphs .106 through .132. If reserves are discovered, each party shall
report its share of reserves and production (refer to paragraphs .160 through .167).


Farmouts, Carried Interests, and Unitizations

Chapter 23

390

To illustrate a free well scenario, assume ABC owns several unproved leases in the Little
River area. In January of the current year, it contracts with Freeco to drill and equip a well
on the property—at Freeco’s cost. In return, ABC assigns an undivided one-half working
interest in the Downy lease to Freeco. ABC’s original cost of the lease was $24,000.
Freeco spends $125,000 on intangibles and $30,000 on equipment for the property,

which is considered proved after the well is completed. Each party receives one-half of
the production revenues, beginning with the first production, and each bears one-half of
operating expenses and further developmental costs.
Since the transaction comes under the pooling of capital concept, the accounting
treatment for both parties is essentially the same as accounting for farmouts. Assuming
group impairment method is used, the entry required by ABC is:
221

Proved Property Acquisition Costs
211

24,000
24,000

Unproved Property Acquisition Costs

To transfer cost of Downy lease to proved leaseholds.

For Freeco, the transaction is expressed in the following summary journal entry:
231

Intangible Costs of Wells and Development

125,000

233

Tangible Costs of Wells and Development

30,000


101

155,000

Cash

To record costs of a free well drilled for a fractional interest in Downy
lease.

Under this procedure, ABC assigns no cost to IDC or equipment, and Freeco assigns no cost
to the mineral interest. Each party reports only its share of production and proved reserves.
Another type of free well agreement calls for the lessor to retain all of the working
interest and assign the driller a nonoperating interest in the property in return for drilling
and equipping the well. Using data from the preceding example, assume ABC retains the
entire working interest in a lease and assigns Freeco an overriding royalty of one-fourth
of total production from the property in return for Freeco’s drilling and equipping the well.
This transaction represents a pooling of capital because each party contributes property,
money, or services to a joint venture in return for some type of ownership interest. Thus,
no gain or loss is recognized by either party.
As the holder of a nonoperating interest, Freeco has no ownership in either the IDC or
equipment. It might appear that the entire $155,000 spent by Freeco should be treated
as the cost of the overriding royalty. However, since Oi5.138c specifically prohibits
classifying a portion of well costs to an earned mineral interest, it is more consistent with
Oi5 conveyance rules for Freeco to treat the entire $155,000 as well costs.

CARRIED INTERESTS
For many years, carried interests have been widely used in the oil and gas industry.
While various forms exist, all achieve the same economic result. A Manahan contract is a
common type of carried interests arrangement and is illustrated in the following example.

ABC, the carried party, owns the working interest in an unproved lease named A1. It
assigns its entire interest to Developco, the carrying party. Developco agrees to pay all
costs of drilling, equipping, and operating the property until the entire amount is recovered
out of working interest revenue. This period is referred to as the time of payout. Developco


Farmouts, Carried Interests, and Unitizations

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then reassigns one-half of the working interest to ABC (which has a 50% reversionary
interest). At that time, ABC and Developco share equally in further revenues and production
expenses and any additional expenditures for drilling or development.
ABC’s cost of the lease is $20,000. Developco spends $100,000 for IDC and $32,000
for equipment placed on the lease. The well is completed and production begins on
November 1, 2006. Working interest revenue is $30,000 per month (for 500 barrels)
beginning with the first production and expenses are $8,000 per month. On December
31, 2006, proved reserves attributable to the working interest are 390,000 barrels. Based
on these facts, Developco has $22,000 per month of net revenue ($30,000 revenue less
$8,000 expenses) to apply toward recoupment of drilling and development costs. At the
end of 2006, Developco has received $44,000 (two months at $22,000) and is entitled to
recover an additional $88,000 ($132,000 - $44,000) out of revenue before ABC begins to
share in production.
The accounting treatment specified by Oi5.138(d) for carried interests is summarized
as follows:
1. No gain or loss is recognized by either party at the time of conveyance.
2. The expenditures or contributions of each party are accounted for in a
proper manner by the party making the expenditure or contribution.

3. All revenue and cash expenses belong or apply to the carrying party until
payout; except for the entry to transfer the property’s cost to Proved
Properties, no entries are necessary by the carried party until that time.
Since neither party records gain or loss on the conveyance transaction, ABC transfers
the leasehold cost of $20,000 (or net book value, if impairment has been recorded on an
individual lease basis) to Proved Leaseholds when the property becomes proved.
221

Proved Property Acquisition Costs
211

20,000
20,000

Unproved Property Acquisition Costs

To record proving of the A1 lease carried by Developco.

Since Developco is considered to own the full working interest until payout, its costs of
drilling and equipping the well are recorded in the following journal entry:
231

Intangible Costs of Wells and Development

100,000

233

Tangible Costs of Wells and Development


32,000

101

132,000

Cash

To record drilling and equipment costs on the A1 lease.

As mentioned, Developco is entitled to recover its expenses related to the property until
it receives the entire amount due. If cash proceeds from the property are inadequate, ABC
has no liability for unrecovered amounts. Developco has $22,000 per month of net revenue
($30,000 revenue less $8,000 expenses), which is $44 for each working interest barrel
($22,000/500 barrels) to apply toward recoupment of drilling and equipment costs. Thus,
in November and December of 2006, Developco includes all the revenue and expenses in
its income statement as summarized (for the two months) in general journal form:
101

60,000

Cash
601

Crude Oil Revenues

To record production revenues from the A1 lease.

60,000



Farmouts, Carried Interests, and Unitizations

Chapter 23

701

392

16,000

Lease Operating Expenses
101

16,000

Cash

To record production expenses on the A1 lease.

Since all working interest production during payout belongs to the carrying party, its
reserves disclosures should include all working interest production expected until payout,
plus the carrying party’s share of reserves at payout. The reserves quantity to be reported
by the carried party prior to payout (and used in computing DD&A after payout) is the
carried party’s share of reserves at payout.
On December 31, 2006, the proved reserves attributed to each are computed as follows:
Barrels
December 31, 2006, total working interest share of proved reserves
Less barrels expected to be produced from December 31 to date of
payout attributed to the carrying party ($88,000 divided by $44 per barrel)


390,000

Expected reserves at date of payout

388,000

(2,000)

Reserves attributable to carrying party (Developco):
Barrels to be produced until payout

2,000

One-half of reserves at payout

194,000

Total to carrying party

196,000

Reserves attributable to carried party (ABC):
One-half of reserves at payout

194,000

ABC has no revenue from production during 2006 and records no DD&A for the year.
Developco does not record leasehold costs. However, IDC and equipment amortization
are recorded by Developco in 2006 and computed assuming net DR&A costs are zero:

IDC
1,000/(1,000 + 196,000) x $100,000

=

1,000/(1,000 + 196,000) x $ 32,000

=

Equipment

$508
$162

Once payout has been reached, each party reports its share of revenue, lifting costs,
and additional drilling and development costs in the usual way. Continuing the preceding
illustration, assume the following data in 2007 for the A1 lease:
• Production and sales (working interest share):
January through November 2007
December 2007

500 bbls per month
750 bbls

• Sales price per barrel for 2007

$60 per bbl

• Lifting costs:
January through November 2007

December 2007

$ 8,000 per month
$12,000

• Additional costs on well completed in November 2007:
IDC
Tangible Equipment

$120,000
30,000


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• Proved developed reserves of 562,500 bbls for 100 percent working interest
as of December 31, 2007
• No proved undeveloped reserves
Computations of revenue and expense items to be reported by each party in accordance
with Oi5 conveyance rules are:
Revenues:
Barrels

Price

Revenue


2,000
1,750
375
4,125

$60
60
60

$120,000
105,000
22,500
$247,500

0
1,750
375
2,125

$ 0
60
60

$
0
105,000
22,500
$127,500


$8,000/mo x 4 mos
0.50 x $8,000/mo x 7 mos
0.50 x $12,000

=
=
=

$32,000
28,000
6,000
$66,000

0.50 x $8,000/mo x 7 mos
0.50 x $12,000

=
=

Developco:
Jan 1 through payout on Apr 30
May 1 through Nov 30
December
Total
ABC:
Jan 1 through Apr 30
May 1 through Nov 30
December
Total


Production Expenses:
Developco:
Jan 1 through Apr 30
May 1 through Nov 30
December
Total
ABC:
Jan 1 through Apr 30
May 1 through Nov 30
December
Total

$
0
28,000
6,000
$34,000

Amortization of mineral interest cost:
Developco:
ABC:

$0
2,125 bbls
2,125 bbls + .50(562,500 bbls)

x $20,000 =

$150



Farmouts, Carried Interests, and Unitizations

Chapter 23

394

IDC and equipment amortization (assuming net DR&A costs are zero):
Developco (assuming an annual computation):

IDC

4,125/[4,125 + (.50 x 562,500)] x [$100,000 + (.50 x $120,000) - $508] =

Equipment

$2,305

4,125/[4,125 + (.50 x 562,500)] x [$32,000 + (.50 x $30,000) - $162) =

$ 677

ABC:

IDC

2,125/[2,125 + (.50 x 562,500)] x (.50 x $120,000) =

$ 450


2,125/[2,125 + (.50 x 562,500)] x (.50 x $30,000) =

Equipment
$ 112

The information ultimately reflected in the accounts of the two companies for 2007 is
shown in the following summary journal entries:


Developco

231

Intangible Costs of Wells and Development

60,000

233

Tangible Costs of Wells and Development

15,000

101

ABC
60,000
15,000

75,000


Cash

75,000

To record additional development costs on the A1 lease.
101

247,500

Cash
601

127,500
247,500

Crude Oil Revenues

127,500

To summarize 2007 production revenues from the A1 lease.
710

Lease Operating Expenses
101

66,000

34,000
66,000


Cash

34,000

To record 2007 production expenses on the A1 lease.
732

Amortization of Intangible Costs of Wells
232

734

Amortization of Tangible Costs of Wells
234

2,305

Accum. Amortization of Tangible Costs of
Wells and Development

450
2,305

Accum. Amortization of Intangible Costs of
Wells and Development
677

450
112


677

112

To record 2007 amortization on wells and facilities on the
A1 lease.
726

Amortization of Proved Property Acquisition Costs
226

Accumulated Amortization of Proved Property
Acquisition Costs

150
150

To record 2007 depletion on the A1 lease.

As previously noted, contract terms that create carried interests can vary. For example,
a nonconsent clause in a joint venture operating agreement may give rise to a carried
working interest. ABC might propose that an additional well be drilled to fully exploit a
reservoir. If Developco elects to not participate, it has gone nonconsent on the well. The
operating agreement typically entitles ABC to drill and produce the well, receive all working


395

Farmouts, Carried Interests, and Unitizations


Chapter 23

interest revenues, and pay all operating costs until it recovers a specified multiple (e.g.,
300 percent) of all costs of drilling and equipping the well. When the multiple is achieved,
payout occurs. From this point forward, Developco participates in the well’s revenues and
costs based on its working interest—as though the nonconsent had not happened. See
a nonconsent provision in CD Reference Exhibit E, Article VI, (B).
For additional guidance, refer to COPAS Accounting Guideline No. 13 (AG 13), Accounting
for Farmouts/Farmins, Net Profits, Carried Interests.

PROMOTED VS. PROMOTING
In most joint ventures, the venturers share both costs and revenue in proportion to their
ownership interests in the properties. For example, assume joint venture partners A and B
each have a 50 percent working interest and a 45 percent net revenue interest in a venture
(the lessor has a 10 percent net revenue interest in the form of a royalty interest). Since
the parties share costs and revenues in the same proportions, this type of joint venture is
sometimes referred to as a straight-up arrangement.
In some cases, costs and net revenue are not shared in the same ratios. A joint venture
agreement may call for joint venturers X and Y to each receive 45 percent of the net revenue
(the other 10 percent going to the royalty holder), but X bears 40 percent of costs and Y
bears 60 percent of costs. In this situation, X is said to be the promoter or promoting party
and Y the promoted party. Such an arrangement might occur if X originally owned 100
percent of the working interest in an attractive property and agreed to let Y have half of the
working interest’s 90 percent share of revenues in return for Y paying 60 percent of costs.

UNITIZATIONS
An important type of sharing arrangement is known as a unitization. In this case, all
owners of operating and nonoperating interests pool their property interests in a producing
area (normally a field) to form a single operating unit. In return, they receive participation

factors, which are undivided interests in the total unit (and are either operating or nonoperating based on the properties contributed).
Unitizations are designed to achieve the most efficient and economical exploitation of
reserves in an area. The arrangement can be voluntary or it may be required by federal
or state regulatory bodies. Unitizations are common in fields with primary production and
are even more widely utilized for reservoir-wide enhanced recovery operations (explained
in Chapter 32).
Unitizations are also popular on offshore properties where costs are high and reserves
may be justified on an individual basis. Joint development of an area can make a unit more
economically feasible. Units involve more than one lease and have diverse ownerships of
various mineral interests and reservoirs that cross lease boundaries.
Shares in the unit that participating owners receive—participation factors—are based
on acreage, reserves, or other criteria with respect to each lease to be placed in the unit.1
Participation factors do not usually give weight to the stage of development of properties.
Leases are often in different phases of development with some leases being fully drilled
and equipped, others being partially developed, and some completely undeveloped.
Percentages are subject to revision within a specified subsequent period as additional
information about the reserves becomes available. Accounting challenges resulting from
subsequent adjustments are discussed later in this chapter.


Chapter 23

Farmouts, Carried Interests, and Unitizations

396

EQUALIZATIONS
Unit participants with undeveloped leases in the unit are normally required to pay cash
to participants with fully or partially developed leases in order to equalize the capital
contributions of wells and equipment.

For example, assume the 600 acre Ajax lease is 100 percent owned by Company A.
It will be unitized with an adjoining 400 acre tract known as the Brown lease, which is
owned 100 percent by Company B. Unit participation factors are based on acreage. Thus,
Company A receives a 60 percent participation factor, and Company B is allotted a 40
percent participation factor for both unit costs and unit revenue. Company A pays the Ajax
lease royalty based on A’s share of revenues. Company B pays the Brown lease royalty
based on B’s share of revenues. Prior to unitization, Company A spent $700,000 on two
wells, and Company B spent $300,000 on one well. Terms of the unitization agreement
require that $1,000,000 of prior well costs be reallocated so the sharing of prior well
costs equals the sharing of post-unitization costs and revenue. As a result, Company B
pays $100,000 to Company A at the time of unitization so that A’s adjusted well cost is
$600,000, or 60 percent of total well costs, and B’s adjusted well cost is $400,000. Such
adjustments are called equalizations.
Equalizing Pre-Unitization Costs. In new fields where development is not completed,
it is common for an equalization agreement to be based on expenditures for exploration
and drilling that occurred prior to the date of unitization. Four steps are involved in the
unitization process:
1. Identifying pre-unit contributions to be allowed in computing equalization
2. Accumulating or collecting contributions from each pre-unit working
interest owner
3. Calculating the obligation of each working interest owner for pre-unit costs
4. Determining settlement for underspent and overspent amounts
Generally, expenditures made for wells and facilities that directly benefit the unit are
accepted for equalization; costs that relate to other wells and facilities that do not benefit
the unit are not equalized. Costs to be equalized almost always include direct costs such
as labor, employee benefits, taxes, construction charges, costs of special studies, and
other expenditures that can be specifically identified with individual wells and equipment.
In addition, geological and geophysical costs, permits, and environmental study costs
may be considered direct charges.
Overhead not directly related to individual wells and facilities may be equalized. These

costs include such items as offsite labor, administrative charges, and the cost of operating
district or regional offices. Parties frequently limit overhead to a percentage of direct costs
or a specified fixed annual fee. Actual time worked by personnel on the properties may
also be equalized.
In addition to direct costs and overhead, unitization agreements may permit an
equalization of risk charges or imputed risk charges. For example, insurance costs incurred
in transporting equipment and facilities or the imputed costs of insurance to cover facilities
prior to unitization may be considered. Finally, equalization agreements may provide for an
inflation factor to reimburse parties for changes in purchasing power between the time of
the original investment and ultimate recovery from other owners.
Cash Equalization. The unitization process is a pooling of capital to achieve a common
benefit for all parties. Normally, no gain or loss is recognized by any party to the unitization.


Farmouts, Carried Interests, and Unitizations

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A party making a cash equalization payment increases its recorded investment in wells
and related equipment and facilities. On the other hand, a participant who receives a cash
equalization payment reduces the recorded investment in the wells and related equipment.
Oi5.138(f) contains the following accounting guidelines for unitizations:
Because the properties may be in different stages of development at the time of
unitization, some participants may pay cash and others may receive cash to equalize
contributions of wells and related equipment and facilities with the ownership interests
in reserves. In those circumstances, cash paid by a participant shall be recorded
as an additional investment in wells and related equipment and facilities, and cash
received by a participant shall be recorded as a recovery of costs. The cost of the

assets contributed plus or minus cash paid or received is the cost of the participant’s
undivided interest in the assets of the unit. Each participant shall include its interest in
reporting reserve estimates and production data.
The simplified example that follows demonstrates the financial accounting treatment
required by Oi5.138(f) at the time of unit formation. Assume three E&P companies are
involved in a unitization of their respective properties, all of which have been developed.
Based on several factors, such as acre-feet of sand contributed, each party is allocated a
one-third interest in the unit. The unitization agreement provides specifically:
Inasmuch as the values of wells drilled and of wells and other operating equipment
on the separately owned tracts is not in proportion to the participating interest of
the owners of such tracts, and such values have not entered into the determination
of the participation percentages, a separate exchange of interest in wells and well
equipment, lease equipment, and other operating equipment will be made between
the parties hereto.
In order to give each party credit for IDC and equipment, cash equalization calculations
are made. In the following table, the undepreciated balance of well costs on each party’s
books is shown in Column (2). Column (3) represents the agreed-on value of the well costs
contributed by each party based on current costs to drill the usable wells contributed
by each party, and Column (4) reflects the share of the agreed-on value of well costs
belonging to each party after the unitization. Cash is contributed or received by each party
to equalize the value of well costs received and contributed as shown in Column (5). (In
newly developed fields the agreed-on value is usually considered equal to allowable costs
incurred by each party for exploration and development prior to the unitization.)
Equalization for IDC:
(1)

(2)
Unamortized
Balance


(3)
Value
Contributed

A

$300,000

$ 550,000

$ 400,000

$ 150,000

B

260,000

375,000

400,000

( 25,000)

C

320,000

275,000


400,000

(125,000)

$1,200,000

$1,200,000

Party

Total

(4)
Value
Received

(5)
Cash
Equalization

$

0


Farmouts, Carried Interests, and Unitizations

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398


Equalization for equipment:
(1)

(2)
Unamortized
Balance

(3)
Value
Contributed

A

$20,000

$ 50,000

$ 60,000

$(10,000)

B

70,000

65,000

60,000


5,000

C

65,000

65,000

60,000

5,000

$180,000

$180,000

Party

Total

(4)
Value
Received

(5)
Cash
Equalization

$


0

Mineral Rights Equalization. Monetary entries are not necessary to record the
exchanges of mineral rights in property transferred to the unit for a share of minerals in
return. Parties treat the book value of their contributed property as their investment in
the mineral interest in the unit. Most unitization agreements, especially when some of the
properties have not been fully developed, call for one or more subsequent evaluations and
readjustment of participation factors. This topic is discussed later in the chapter.
IDC Equalization. Party A receives $150,000 cash as equalization for IDC. In accordance
with Oi5.138(f), the cash received is treated as a reduction of investment:
101

150,000

Cash
231

Intangible Costs of Wells and Development

150,000

To record receipt of cash on IDC equalization.

Since the unamortized balance of A’s IDC contribution is greater than the amount of
cash received, the equalization payment merely reduces the investment.
Both B and C must make cash payments to equalize IDC. Under Oi5.138(f), payments
are capitalized as additional investment in IDC.
Equipment Equalization. Both B and C receive cash in equalization of equipment
contributions. In each case, the amount of cash received is less than the book value of
equipment contributed; therefore, the full amount received is credited to Account 233,

Tangible Costs of Wells and Development.
Equalization in Excess of Cost. Due to the valuation process, in which valuations are
made and current pricing is taken into account, it may be possible to receive equalization
credit in excess of cost. After equalization, the carrying value of a well may be negative for
book purposes, but individual asset-carrying values within a proven property asset pool are
generally not important under either successful efforts or full cost accounting methods.
Disproportionate Spending Equalization. Certain parties may strive to avoid
cash equalization. In this case, equalization occurs by adjusting the amount of future
expenditures to be paid by each party to compensate for disproportionate contributions.
This technique is especially common in new fields where there has been little drilling
activity up to the time of unitization.
To illustrate a cost-equalization program involving disproportionate spending, the
following schedule shows the working interest ownership of each party, pre-unit costs,
costs to be borne by each party, and over/underspent positions of each:


Farmouts, Carried Interests, and Unitizations

399

Chapter 23

Table 1

Company

Working Interest
Ownership

Pre-unitization

Costs Incurred

Proportionate
Share

Over (Under)
Spent

Acorn

50%

$1,000,000

$ 750,000

$250,000

Barn

35

300,000

525,000

(225,000)

Check


15

200,000
$1,500,000

225,000
$1,500,000

(25,000)
$
0

Since actual expenditures incurred by Acorn Company prior to unitization exceed
its proportionate share of total costs of $1,500,000, Acorn pays no part of costs after
unitization until the other companies have overspent their shares by the same amount. The
subsequent overspending by the two parties that were underspent is shared in the ratio
of the proportionate interest of the shortfall. Thus, in the example above, Barn Company
will absorb 90 percent (225/250), and Check Company will absorb 10 percent (25/250)
of the first $250,000 of future expenditures to bring the parties back in balance to their
proportionate working interests.
A reasonable interpretation of the provisions of Oi5.138(f) relating to sharing arrangements
suggests that each party should account for actual expenditures in the regular manner.
Equalization Resulting from Redetermination of Interests. As pointed out
previously, unitization agreements often contain provisions requiring the ownership to
be redetermined and adjusted at dates subsequent to the date of unitization. These
adjustments are based on changes in estimates of recoverable reserves that result from
improved technical knowledge of the reservoir as the field is developed and oil and gas are
produced. Between the dates of the unitization and subsequent readjustment, production
revenues as well as operating expenses and development costs are allocated on the basis
of the percentages of ownership interest in effect.

When a redetermination is made, it may be retroactively applied to the date the unit was
formed. In other cases, the effective date occurs later such as when a discovery changes
the size and extent of the proved portion(s) of reserves. As a result, an equalization
computation is made at the date of redetermination to equalize production proceeds and
costs incurred during the period. It is customary for equalization of production revenue
to be handled through undertakes and overtakes of subsequent production, rather than
through cash settlements. Equalization of post-unitization costs incurred is handled
through disproportionate spending equalization as previously described.
For example, assume a unitization agreement becomes effective January 1, 2004, at
which time equalization for prior expenditures is made through a cash settlement. The initial
agreed-upon ownerships are 30 percent to Company X, 50 percent to Company Y, and 20
percent to Company Z. The agreement calls for a redetermination of ownership interests
on January 1, 2007, based on revised estimates of oil and gas reserves contributed to
the unit by the parties. During the three-year period prior to redetermination, production
totaled 10 million barrels at an average price of $60 per barrel. Development expenditures
of $30 million for drilling costs and $10 million for equipment and facilities were incurred.
Operating expenses were $10 million. All revenue and costs were shared in the original
agreed-upon ratio of 30 percent, 50 percent, and 20 percent.
On January 1, 2007, a redetermination is made and working interests are readjusted
as follows: X receives 27 percent; Y receives 55 percent; and Z receives 18 percent.


Farmouts, Carried Interests, and Unitizations

Chapter 23

400

Equalization for the over/undertake of production prior to the redetermination is
accomplished by offsetting over/undertakes of production over the two-year period

following redetermination. Equalization of over-expenditures and under-expenditures for
development costs and operating expenses is accomplished through an adjustment of
costs incurred after the redetermination of interests.
Thus, during each month of the two-year period following redetermination, Company
Y receives 20,833 barrels in excess of its normal share of production, and shares of
Company X and Company Z are reduced by 12,500 barrels and 8,333 barrels per month,
respectively, in order to correct the misallocation of prior production.
Table 2
(in barrels)

Initial
Allocation
of Production

Redetermined
Allocation
of Production

X

3,000,000

Y

5,000,000

Z

2,000,000


Company

Over (Under)
Produced

Monthly
Equalization
Over 24 Months

2,700,000

300,000

(12,500)

5,500,000

(500,000)

20,833

1,800,000

200,000

(8,333)

Assuming that production in the first month following redetermination is 300,000 barrels,
it would be allocated as follows:
Table 3

Normal
Allocation of
Production
(bbls)

Equalization
Adjustment
(bbls)

Total Share
of
Production
(bbls)

Company

Percent of
Working Interest

X

27

81,000

(12,500)

68,500

Y


55

165,000

20,833

185,833

Z

18
100

54,000
300,000

(8,333)
0

45,667
300,000

Total

The tables indicate equalization of production quantities, but not revenues. To equalize
revenues, the actual monthly price of oil (or gas) after the redetermination is compared to the
average price received prior to redetermination, which was $60 per barrel. Any variance in
price is considered in the equalization redetermination. This calculation can be done monthly,
but due to timing and information flow, the adjustment would normally be in arrears.

Table 4

Company

Monthly
Equalization
(bbl)

Pre-equalization
Price

January 2007
Price

January
Revenue
Equalization

X

(12,500)

$60/bbl

$65/bbl

$62,500

Y


20,833

60/bbl

65/bbl

(104,165)

Z

(8,333)

60/bbl

65/bbl

41,665


401

Farmouts, Carried Interests, and Unitizations

Chapter 23

Company X gave up 12,500 barrels in January worth $65 per barrel to compensate for
taking 12,500 barrels in prior months at $60 per barrel, so the revenue equalization gives
Company X $62,500 for the $5/bbl differential.
Equalization of development costs and operating expenses are accomplished through
disproportionate spending equalization in the manner illustrated previously.

Under the general rules established for poolings of capital in Oi5.135 and Oi5.138,
no accounting entries are necessary at the time of post-unitization redetermination
of interests. It is appropriate for each owner to report revenues actually received,
reflecting any increase or decrease due to an adjustment, and for each party to
account in the usual way for all costs incurred. Reserve disclosures reflect readjusted
amounts, and future depreciation, depletion, and amortization calculations are based
on the revised estimates.
UNITIZATION ON FEDERAL LANDS
Unitizations on federal land have unusual features that complicate accounting for them.
Federal unitization is a two-step process. First, lessees of federal mineral rights in a large
prospective area of perhaps several thousand acres (the unit area) sign an exploratory unit
agreement and a unit operating agreement to “adequately and timely explore and develop
the committed leases within the unit area without regard to the interior boundaries of the
leases.”2 Second, as proved areas within the unit become known, leaseholders within the
areas (called a participating area or PA) are required to form a joint venture to develop and
operate the participating area and share in costs and revenues. A PA expands as new
wells extend the proved area, or it may contract as dry holes and uneconomic wells are
drilled and define the productive area. Two or more PAs may combine into one large PA
as new wells demonstrate the continuity of the underlying reservoir. A large unit area may
have more than one PA when the unit area is ultimately developed.
Often, a PA interest is determined by relative acreage of the lease areas within the
PA. A company’s 100 percent working interest in a 320-acre lease with one well may
become a 50 percent working interest in a two-well or three-well 640-acre PA. As the
PA expands to 3,200 acres and 15 wells, the company’s PA interest may fall to 10
percent. In this case, the company pays 10 percent of all 15 wells’ costs and receives
10 percent of the PA revenues after royalties, assuming uniform royalty rates. Any
PA formation, expansion, or contraction is approved by the U.S. Department of the
Interior and is generally effective with (and retroactive to) the completion date of the
well that justified the PA change. Hence, a company’s working interest in a PA will vary
as the PA expands or contracts. Accounting for a PA interest is complex and subject

to retroactive adjustment.
A company can elect to go nonconsent and not participate in future wells within the
PA or the unit, subject to a nonconsent penalty.3 However, accounting for nonconsent
interests is difficult and has been the subject of litigation due to internally inconsistent
language in at least three versions of a standard unit operating agreement form used from
1954 through the early 1990s. Further discussion of this issue is beyond the scope of this
book, but it is indicative of the complexity of accounting for PA interests.
Prudhoe Bay Example of Redetermination and Participating Areas. An example
of post-unitization redetermination is described in the excerpt following from the forepart
of the 1999 Form 10-K of BP Prudhoe Bay Royalty Trust. The trust has a net profits
interest akin to a 16.4246 percent ORRI (royalty interest) in British Petroleum’s first 90,000
barrels per day of production from the Prudhoe Bay Unit.4


Farmouts, Carried Interests, and Unitizations

Chapter 23

402

THE PRUDHOE BAY UNIT
GENERAL
The Prudhoe Bay field (the Field) is located on the North Slope of Alaska, 250 miles
north of the Arctic Circle and 650 miles north of Anchorage. The Field extends
approximately 12 miles by 27 miles and contains nearly 150,000 productive
acres. The Field, which was discovered in 1968 by BP [the Company] and others,
has been in production since 1977. The Field is the largest producing oil field in
North America. As of December 31, 1998, approximately 9.7 billion STB (Stock
Tank Barrels5) of oil and condensate had been produced from the Field. Field
development is well advanced with approximately $17.5 billion gross capital

spent and a total of about 1,885 wells drilled. Other large fields located in the
same area include the Kuparuk, Endicott, and Lisburne fields. Production from
those fields is not included in the Royalty Interest.
Since several oil companies hold acreage within the Field, the Prudhoe
Bay Unit was established to optimize Field development. The Prudhoe Bay
Unit Operating Agreement specifies the allocation of production and costs
to Prudhoe Bay Unit owners. The Company and a subsidiary of the Atlantic
Richfield Company (ARCO) are the two Field operators. Other Field owners
include affiliates of Exxon Corporation (Exxon), Mobil Corporation (Mobil),
Phillips Petroleum Company (Phillips) and Chevron Corporation (Chevron).
PRUDHOE BAY UNIT OPERATION AND OWNERSHIP
...The Prudhoe Bay Unit Operating Agreement specifies the allocation of production
and costs to the working interest owners. The Prudhoe Bay Unit Operating
Agreement also defines operator responsibilities and voting requirements and is
unusual in its establishment of separate participating areas for the gas cap and
oil rim....
The ownership of the Prudhoe Bay Unit by participating area as of December 31,
1998, is summarized in the following table:

Oil Rim

Gas Cap

BP

51.22%

13.85%

Arco


21.87

42.56

Exxon

21.87

42.56

Mobil/Phillips/Chevron (MPC)

4.44

1.03

Others

0.60

0.00

100.00%

100.00%

Total

(a)


(a) The Trust’s share in oil production is computed based on BP’s ownership interest of 50.68% as of February 28, 1989.


403

Farmouts, Carried Interests, and Unitizations

Chapter 23

CREATION OF JOINT VENTURES
Prior chapters have noted that E&P joint ventures are common in the U.S. Chapter
10 addresses joint venture operations, billing for joint venture costs, and day-to-day
accounting for joint interests. Oi5.138(e) describes joint ventures and indicates how the
formation of a joint venture is to be accounted for:
A part of an operating interest owned may be exchanged for part of an operating interest
owned by another party. The purpose of such an arrangement, commonly called a joint
venture in the oil and gas industry, often is to avoid duplication of facilities, diversify risks,
and achieve operating efficiencies. No gain or loss shall be recognized by either party at
the time of transaction. In some joint ventures, which may or may not involve an exchange
of interests, the parties may share different elements of costs in different proportions.
In such an arrangement, a party may acquire an interest in a property or in wells and
related equipment that is disproportionate to the share of costs borne by it. As in the
case of a carried interest or a free well, each party shall account for its own cost under
the provisions of this section. No gain shall be recognized for the acquisition of an interest
in joint assets, the cost of which may have been paid in whole or in part by another party.
Two major points from Oi5.138(e) are illustrated in the following example. Assume two
operators own contiguous unproved properties. For the sake of efficiency, they form
a joint venture with ABC Company owning a two-thirds interest and South Company
owning one-third. They cross-assign interests: ABC assigns to South Company a onethird undivided interest in a property (which had a book value of $120,000 and was being

impaired individually), and South Company assigns a two-thirds interest in each of three
leases (which had a cost of $260,000 and are part of a group subject to a group impairment
test). Neither party recognizes a gain or loss on the exchange. ABC removes one-third of
the cost of the lease in which it gives up an interest and one-third of the allowance for
impairment of the lease. The net book value ($40,000) of the one-third interest is assigned
to the two-thirds interest in the three leases acquired from South Company. A $40,000
allocation is made to individual leases (in which interests were acquired) based on relative
market values of the interests. Similar entries are recorded by South Company.
The second point involves disproportionate sharing arrangements. In a different scenario,
ABC, a successful efforts company, owns a lease which cost $30,000 and on which no
impairment has been recorded. It retains one-fourth of the working interest and assigns
three equal interests of one-third of three-fourths of the working interest to other parties,
which will bear the entire cost of drilling the first well. If the first well is to be completed,
all parties, including ABC, are to pay for a proportionate share of completing the well. This
type of arrangement is a “third for a quarter” deal that was common years ago when oil
prices escalated rapidly. The drilling cost on this well amounts to $600,000, which is paid
in equal shares by the other three parties.
ABC retains $30,000 as its leasehold cost. ABC has no intangible cost and records
its share of equipment costs when the costs are incurred. Each assignee accounts for
the $200,000 contributed to the venture as IDC, and each properly accounts for its
cost of equipment subsequently acquired. The assignees do not treat any part of their
contributions as leasehold cost.

FULL COST ACCOUNTING
Reg. S-X Rule 4-10(c)(6) stipulates that, in general, the conveyance rules found in Oi5.133
apply not only to successful efforts companies, but also to companies using full cost.


Chapter 23


Farmouts, Carried Interests, and Unitizations

404

However, Reg. S-X Rule 4-10(c)(6)(iii) adds that under the full cost method, no income
is recognized from the sales of unproved properties or participation in various forms of
drilling arrangements involving oil and gas producing activities, except to the extent of
amounts that are identifiable with the transaction. Problems relating to the formation and
operations of partnerships are discussed in Chapter 24.

TAX ACCOUNTING
Tax accounting for farmouts, carried interests, and unitizations can depend on individual
circumstances and agreement terms. Certain accounting issues are unsettled due to
conflicting court decisions.
For carrying arrangements, carrying parties typically pay 100 percent of IDC and
equipment; however, a portion of these costs may be capitalized as depletable leasehold
investment. If carrying parties own 100 percent of the working interest until payout, then
they deduct (in the manner they would normally deduct their noncarried costs) 100 percent
of the well costs as IDC and equipment depreciation. Upon payout, any undepreciated
equipment costs are reclassified as depletable leasehold costs. Under other conditions
(whereby the carrying parties are not entitled to 100 percent recoupment of the well costs),
some or all of the carried costs are capitalized as depletable leasehold costs.
IRC Sec. 614(b)(3) provides that the taxpayer’s properties in a compulsory unitization are
treated as one property upon unitization. This rule applies to certain voluntary unitizations as
well. Generally, a unitization is viewed as an exchange of the taxpayer’s old properties for a new
property. The transaction can give rise to taxable gain to the extent of cash received to adjust
participants’ share of unit costs. It may also give rise to an exchange of depreciable equipment
costs for depletable leasehold costs—by delaying or eliminating deduction of such costs.
Joint ventures are not generally taxed as corporations, nor are they treated as partnerships.
The joint venture owner’s net share of joint venture revenue and expenses determines the

owner’s taxable income. To avoid corporate status, oil and gas joint venture agreements
typically provide that each joint venture owner has an option to take its oil and gas in-kind.
This option may never be exercised, but it has been viewed as sufficient to eliminate the
joint profit objective regarded in tax rules as inherent to a corporation.
A joint venture can avoid being treated as a partnership by making an election in its
first year (i.e., it elects out of Subchapter K). The election may be evidenced by a specific
provision in the joint venture agreement. Opting out of partnership status has various
advantages such as avoidance of: (1) filing partnership tax returns, (2) maintaining certain
partnership accounting records, and (3) electing to deduct IDC as incurred.
•••
1 A participant’s fractional interest (or participation factor) may be based on any number of reasonable factors—
acreage, estimated reservoir thickness under a given acreage, estimated reserves under a given acreage,
number of producing wells on the acreage, and even prior production history for the acreage.
2 See the Unitization section of the U.S. Department of the Interior Bureau of Land Management’s Handbook
for a discussion of this topic.
3 The concept of nonconsent and nonconsent penalty is addressed briefly in Chapter 10.
4 The trust share in revenue is reduced for certain chargeable costs of several dollars per barrel.
5 Stock Tank Barrel refers to a marketable barrel of crude oil at 60º F and at an atmospheric pressure where:
(1) solution gas has bubbled out of the crude oil, or (2) solution gas and water have been removed from the
produced crude oil.


C H A P T E R

24

Glossary Terms
general partnership
limited partnership
managing partner


ACCOUNTING FOR
PARTNERSHIP INTERESTS
Key Concepts:
• Accounting for general partnership investments
using risk and rewards method, voting interest
method, or proportionate consolidation method
• Reporting limited partnership investment
• Conveyance of mineral interests to the partnership
under full cost and successful efforts accounting
• Treatment of management and service fees
• Master limited partnership issues


Chapter 24

Accounting for Partnership Interests

406

OVERVIEW
A partnership is a business entity with two or more parties that share in the profit or
loss of an activity. Partnerships are legal organizations, which differ from joint operations
that operate under contractual arrangements (see Chapter 10). Oil and gas companies
often form partnerships involved in exploration and production activities for tax purposes.
Whether they are sole proprietors or corporations, operators are eligible to buy into these
entities set up as general or limited partnerships.
When an E&P company invests in a general partnership, it is entering a joint operation
with one or more E&P companies. For tax law or other reasons, the partners do not follow
the common approach to joint operations, which is to operate as undivided interest

holders. Limited partnerships are also attractive forms of organization. Frequently, the
E&P company serves as operating general partner. Limited partners that are individual or
institutional investors are sources of financing for partnership business activities.
Whether an operator is a general partner or participating in a general or limited partnership,
the accounting problems are much the same. Financial statements must be prepared, tax
returns filed, and partners provided with tax information for their own returns. Layers
of complexities are added when special allocations of revenue, expenses, costs to the
partners, and reversionary interests are made. Additionally, filings with the SEC may be
necessary because some limited partnerships are subject to regulations.
For both general and limited partnership investments, there are three major areas of concern:
(1) reporting at the partnership level, (2) reporting at the partner level for the partnership
investment, and (3) accounting for transactions between the partner and the partnership.

GENERAL PARTNERSHIPS
ACCOUNTING AND REPORTING AT THE PARTNERSHIP LEVEL
Partnerships are separate entities from their owners. A general partnership is
one in which all of the partners are general partners and have the right to participate
in management. The costs of organizing a general partnership are usually quite small
and are expensed under the guidance of SOP 98-5, Reporting on the Costs of Startup Activities. The managing partner is responsible for maintaining adequate business
records, filing tax returns, and providing both financial accounting and tax information
to the other partners. Selections of fiscal year and method of accounting (cash versus
accrual) are made. Another choice is necessary if the partnership seeks to comply with
GAAP: to elect either the full cost or successful efforts method of accounting. Sometimes,
records are kept on a tax basis to simplify preparation of federal income tax returns by the
partners. However, this complicates the partners’ accounting for their investments in the
partnership under GAAP.
REPORTING THE PARTNERSHIP INVESTMENT
In accounting for an investment in a partnership, one of three methods is appropriate
depending on the facts and circumstances of the partnership arrangement:
1. Risk and rewards method under FASB Interpretation No. 46 (revised

December 2003) (FIN 46R), Consolidation of Variable Interest Entities
2. Equity method (also called voting interest method)
3. Proportionate consolidation method (in limited circumstances)


407

Accounting for Partnership Interests

Chapter 24

In evaluating consolidation models, guidance under FIN 46R should be applied first. If
it does not apply and the entity is not a variable interest entity (VIE), then the company
needs to evaluate the voting interest/equity model. Each method is discussed in the
chapter sections following.
Risk and Rewards Method. FIN 46R addresses consolidation of an entity where a
company has the controlling financial interest. The rule makes two critical changes in
the consolidation model: (1) it defines when a company should base controlling financial
interest on factors other than voting rights, and (2) it requires a new risk and rewards
model be applied in these situations. Consequently, GAAP now prescribes two accounting
models for consolidation:
• The voting interest model where the investor owning more than 50 percent of
an entity’s voting interests consolidates.
• The risk and rewards model where the party who participates in the majority
of the entity’s economics consolidates. This party could be an equity investor,
other capital provider, or a party with contractual arrangements.
To determine which accounting model applies under FIN 46R, and which party, if any,
must consolidate a particular entity, the partnership must first determine whether the entity
is a voting interest or a variable interest entity (VIE). The FASB coined the term VIE for
entities subject to the risk and rewards model. An entity is considered a VIE if it possesses

one of the following characteristics:
• The entity is thinly capitalized.
• Residual equity holders do not control it.
• Equity holders do not participate fully in an entity’s residual economics.
• The entity was established with non-substantive voting rights.
Under FIN 46R, the party exposed to the majority of the risks and rewards associated
with the VIE is deemed to be its primary beneficiary and must consolidate the entity.
The following are some FIN 46R considerations surrounding joint ventures:
• Reporting enterprises should first consider the business scope exception in
paragraph 4(h) of FIN 46R. When evaluating this scope exception, joint ventures
are excluded from the first criterion (the one that focuses the formation of the
entity) as long as the entity meets the accounting definition of a joint venture.
However, reporting enterprises must also meet the other three criteria in order
to avail themselves of the scope exception.
• Many joint ventures are capitalized through stepped funding arrangements
(equity or debt infusions) that occur over time, rather than at the formation of
the entity. As such, a thinly capitalized joint venture would not have sufficient
equity at risk, which would cause the entity to be considered a VIE under
paragraph 5(a).
• Joint ventures are commonly structured to provide voting rights disproportionate to the investors’ economic rights to the entity. In these situations, the
reporting enterprise must apply the guidance in paragraph 5(c), and the first
criterion would be met. If substantially all activities of the entity either involve
or are conducted on behalf of the party with disproportionately low voting
rights, the entity would be classified a VIE.


Chapter 24

Accounting for Partnership Interests


408

• The joint venture partners should consider whether or not they are related
parties or de facto agents under FIN 46R. Often in these structures, transfer
restrictions placed on one or both parties limit that party’s ability to manage
the economics of its investment in the partnership without prior approval.
If such transfer restrictions do create a de facto agency relationship, the
determination of the primary beneficiary will focus on which party is most
closely associated with the entity. This would call for a qualitative analysis.
• In joint ventures, occasionally one of the joint venture partners manages
the operations under a management contract. The question arises as to
whether that contract constitutes a decision-making arrangement (covered
by paragraphs B18-B21 of FIN 46R) or is merely a service contract (covered
by paragraph B22 of FIN 46R). If all the significant decisions are made jointly
by the joint venture partners, the management contract may be considered
a service contract rather than a decision-making arrangement. As a service
contract, such an arrangement could still be one of variable interest.
FIN 46R does not define a decision maker, but establishes the fee paid to a decision
maker is not a variable interest if certain conditions are met. One of them is the ability to
remove the decision maker. Paragraph B20 of FIN 46R discusses how to determine when
the ability to remove the decision maker is substantive. It states:
The ability of an investor or another party to remove the decision maker (kick-out
rights) does not affect the status of a decision maker’s fees unless the rights are
substantive. The determination of whether the kick-out rights are substantive should
be based on consideration of all relevant facts and circumstances. Substantive kickout rights must have both of the following characteristics:
a. The decision maker can be removed by the vote of a simple majority of the voting
interests held by parties other than the decision maker and the decision maker’s
related parties.
b. The parties holding the kick-out rights have the ability to exercise those rights if
they choose to do so: that is, there are no significant barriers to exercise of the

rights. Barriers include, but are not limited to:
(1)Kick-out rights subject to conditions that make it unlikely they will be
exercisable, for example, conditions that narrowly limit the timing of the exercise
(2)Financial penalties or operational barriers associated with replacing the decision
maker that would act as a significant disincentive for removal
(3)The absence of an adequate number of qualified replacement decision makers
or inadequate compensation to attract a qualified replacement
(4)The absence of an explicit, reasonable mechanism in the contractual
arrangement, or in the applicable laws or regulations, by which the parties
holding the rights can call for and conduct a vote to exercise those rights
(5)The inability of parties holding the rights to obtain the information necessary to
exercise them.
Comments on the Risk and Rewards Method. Appendix A of FIN 46R provides a
simple example for calculating expected losses and expected residual returns on a pool of
financial assets. Paragraph A1 includes the following assumptions for the example:


Accounting for Partnership Interests

409

Chapter 24

a. A single party holds all of the beneficial interests in the entity, and the entity has
no liabilities.
b. There is no decision maker because the entity’s activities are completely
predetermined.
c. All cash flows are expected to occur in one year or not to occur at all.
d. The appropriate discount rate (the interest rate on risk-free investments) is five
percent.

e. No other factors affect the fair value of the assets. Thus, the present value of the
expected cash flows from the pool of financial assets is assumed to be equal to
the fair value of the assets.
Appendix A of FIN 46R illustrates a set of six possible (or estimated) cash flow scenarios
in Table 1. Each of these scenarios is probability weighted, the sum of which represents
the entity’s “expected cash flows.” The entity’s expected cash flows are $795,000, and
the present value of those expected cash flows is $757,143.

FIN 46R, Appendix A, Table 1
Estimated
Cash Flows
$650,000
700,000
750,000
800,000
850,000
900,000

Probability
5.0%
10.0%
25.0%
25.0%
20.0%
15.0%
100.0%

Expected
Cash Flows
$ 32,500

70,000
187,500
200,000
170,000
135,000
$795,000

Fair Value
$ 30,952
66,667
178,571
190,477
161,905
128,571
$757,143

In Table 2 of Appendix A, for each scenario where the estimated cash flow is less than
the expected cash flow of the entity, there is an expected loss. For example, in the first
scenario the estimated cash flows are $650,000 and the expected cash flows of the
entity are $795,000, resulting in negative deviation in that scenario of $145,000. When
probability-weighted and present-valued, the expected loss generated by the first scenario
is $6,905. The sum of all of the scenarios in which the estimated cash flows are less than
the expected cash flows equals the total expected losses of the entity ($26,667).

FIN 46R, Appendix A, Table 2

Estimated
Cash Flows
$650,000
700,000

750,000
800,000
850,000
900,000

Expected
Cash Flows
$795,000
795,000
795,000
795,000
795,000
795,000

Difference
Estimated
(Losses)
Residual
Returns
$(145,000)
(95,000)
(45,000)
5,000
55,000
105,000

Probability
5.0%
10.0%
25.0%

25.0%
20.0%
15.0%
100.0%

Expected
Losses Based
on Expected
Cash Flows
$ (7,250)
(9,500)
(11,250)

Expected
Losses Based
on Fair Value
$ (6,905)
(9,048)
(10,714)

$(28,000)

$(26,667)


Accounting for Partnership Interests

Chapter 24

410


FIN 46R, Appendix A, Table 3

Estimated
Cash Flows
$650,000
700,000
750,000
800,000
850,000
900,000

Expected
Cash Flows
$795,000
795,000
795,000
795,000
795,000
795,000

Difference
Estimated
(Losses)
Residual
Returns
$(145,000)
(95,000)
(45,000)
5,000

55,000
105,000

Probability
5.0%
10.0%
25.0%
25.0%
20.0%
15.0%
100.0%

Expected
Residual
Return Based
on Expected
Cash Flows

Residual
Expected
Return Based
on Fair Value

$ 1,250
11,000
15,750
$ 28,000

$ 1,191
10,476

15,000
$ 26,667

The same calculation is performed for the expected residual returns, only using the
scenarios where the estimated cash flows are greater than the expected cash flows. In
Table 3, the entity’s expected residual returns are calculated as $26,667. It is no coincidence
these two amounts are equivalent, since an entity’s expected losses will always equal its
expected residual returns as a result of this calculation.
While these examples demonstrate the mathematics behind the calculation of expected
losses and expected residual returns, there is little guidance on how a reporting enterprise
would derive the cash flow estimates necessary to perform these calculations. It is clear
the first step for a reporting enterprise, according to the guidance in paragraph 8 of FIN
46R, is to identify the variable interests in the entity. Variable interests in an entity are
those assets, liabilities, or equity that absorb an entity’s variability. For purposes of the
expected loss calculation, net assets of the entity are those assets and liabilities that
create variability in the entity and, thus, are not variable interests. It is the estimated/
expected changes in the fair value of these net assets that drive the estimated cash flow
scenarios in the calculation of an entity’s expected losses and expected residual returns.
Voting Interest or Equity Method. Under the voting interest method (or equity
method), a partner’s initial investment is recorded in an account with a title such as
Investment in OPQ Partnership. At the end of the fiscal period, the partner’s share of
income (or loss) is recorded as an increase (or decrease) in the investment account and
appears as a single amount under a heading such as Income from OPQ Partnership in the
income statement. The balance in the investment account is shown as a single amount on
the partner’s balance sheet under the heading of Investments.
Comments on the Voting Interest or Equity Method. Under the equity method,
neither the share of the investee’s reserves nor the share of the investee’s oil and gas
assets enter into the depreciation, depletion, and amortization calculation of the investor
under either the full cost or successful efforts methods. Disclosures required by FAS 69
include separate disclosures of the enterprise’s share of the investee’s:

• Proved oil and gas reserves
• Standardized measure of discounted future net cash flows
• Capitalized costs relating to oil and gas producing activities
• Costs incurred in oil and gas property acquisition, exploration, and development
• Results of operations from producing activities
These requirements are discussed further in Chapters 28 and 29.


411

Accounting for Partnership Interests

Chapter 24

The equity method is used by many operators who invest in oil and gas partnerships. It
is justified on the basis of APB No. 18, The Equity Method of Accounting for Investments
in Common Stock. APB 18 was written to provide guidelines for investments in corporate
stock, but AICPA Accounting Interpretation No. 2 suggests many of the provisions of APB
18 are appropriate guides for investments in partnerships. The opinion suggests the equity
method should be used when an investor has the ability to exercise significant influence
over operating and financial plans of the investee. It presumes if the investor owns 20
percent or more of the investee’s stock, the investor exercises significant influence.
APB 18 does not apply, however, when more than 50 percent of the investee’s stock is
owned. A full consolidation of the statements of the two entities is normally required in
this case.
It would seem the same logic should apply to partnership investees. However,
proportionate consolidation of the partnership, rather than full consolidation, is usually
made when the investor’s ownership interest is greater than 50 percent.
A major shortcoming of the equity method is full disclosure of all pertinent financial
information is not given in the financial statements. Off-balance-sheet financing may

result because the investor can be liable for significant partnership debts not reflected in
the balance sheet. Paragraph 20 of APB 18 indicates disclosure of summarized financial
information of such investees may be appropriate for material investments. (When the
proportionate consolidation method is used, an investor discloses its proportionate share
of each of the investee’s applicable disclosure items, regardless of whether full cost or
successful efforts is followed.)
Proportionate Consolidation Method. When using the proportionate consolidation
method, a partner includes a proportionate share of each partnership asset and liability
in the partner’s balance sheet and each revenue and expense in the partner’s income
statement. Although it is possible for the partner to maintain actual accounts reflecting
the ownership share in each partnership item, it may be easier in some cases for the
partner to use the equity method of accounting for the transactions with the partnership
during the fiscal period, and then at the end of the fiscal period eliminate the investment
account and substitute the appropriate amounts of the partnership’s assets and liabilities.
Similarly, the Share of Income or Loss of the Partnership account would be eliminated,
and the proper share of individual revenue and expenses would be substituted in the
income statement.
As an example, assume X Corporation uses the successful efforts method of accounting,
as does OPQ Partnership in which X Corporation owns a one-fourth interest. X Corporation
invested $750,000 for that interest on January 2, 2006. For 2006, OPQ Partnership has a
$1 million loss. OPQ’s 25 percent share is $250,000 before $80,000 in related income tax
reduction. Figure 24-1 illustrates the equity and proportionate consolidation methods for
X Corporation’s share of OPQ Partnership’s loss.
Necessary data for the proportionate consolidation is obtained from financial reports
provided by the partnership at the end of the fiscal period (as long as the partnership and
the partner use the same accounting method and have the same fiscal year).
If there are special allocations of revenues or expenses, or if the accounting method used
by the partnership is different from that of the partner, a reconstruction or reconciliation
must be performed. This can be done based on the periodic reports of partnership
expenditures and revenues prepared by the managing partner.