Mata kuliah : F0074 - Akuntansi Keuangan Lanjutan II
Tahun
: 2010
Corporate Liquidation and Reorganization
Pertemuan 25-26
AICPA Accounting
Standards Executive
Committee
Oil and Gas Accounting
Background and Accounting
Methods
Oil & Gas Accounting Background
• 1950’s and 1960’s: Diversity in practice in accounting for oil
and gas activities. Two methods - Full Cost and Successful
Efforts
• 1970’s: FAS No. 19, “Financial Accounting and Reporting
for Oil and Gas Producing Activities,” is issued. Prescribes
SE method be followed
• SEC issues several Accounting Series Releases that allow
companies to follow either method and provide guidance on
applying the different methods
• FAS No. 25 issued. Makes the SE method of accounting
preferable, but not mandatory.
Two Types of Accounting Methods
• FULL COST - Basic Concept
– All costs associated with property acquisition, exploration
and development activities shall be capitalized by countrywide cost center.
• SUCCESSFUL EFFORTS - Basic Concept
– Costs associated with property acquisition, exploration and
development activities shall be capitalized if they directly
result in the finding or development of proved reserves.
Costs not directly resulting in proved reserves shall be
expensed.
AICPA Accounting
Standards Executive
Committee
Acquisition and Retention
Costs
Acquisition and Retention Costs
• Acquisition Costs
• Retention / Holding Costs
– Delay Rentals
– Ad Valorem Taxes
– Shut-in Royalties
– Legal Costs for Title Defense
– Maintenance of Land and Lease Records
• Disposition of Capitalized Acquisition Costs
– Impairment
– Abandonment
– Transfer (Reclassification) to Proved Property
The Lease Agreement
Mineral interest owner (fee owner or lessor) leases E&P rights to the
working interest owner (lessee), the lease agreement:
–
–
–
–
Defines the lessee and lessor
Clearly defines the leased property
States the consideration (“bonus”) paid by lessee to lessor
States the amount of royalty retained by the lessor (e.g.,1/8 of
production sales proceeds)
– States the “primary term” (e.g., three years)
– Calls for annual “rentals” or delay rentals if drilling has not yet
commenced or production established
– Contains a clause perpetuating the lease if oil or gas production is
established
Types of Mineral Interests
• Fee interest
• Mineral interest
• Working interest (Operating Interest)
• Royalty interest (Non-operating Interest)
• Overriding royalty interest (Non-operating)
• Net profits interest (Non-operating)
• Production payment (Non-operating)
• Farm-out
• Free well agreement
• Reversionary or carried (a.k.a. Disproportionate or promoted
interests)
• Unitization
Accounting for Acquisition and
Retention Costs – Successful Efforts
Method
• Lease acquisition (CAPITALIZE DIRECT
ACQUISITION COSTS)
– Bonus payments, advance payments, options
• Retention Costs (EXPENSE AS INCURRED)
– Delay rentals, property taxes, defense costs, shut-in
royalties
• Disposition of capitalized acquisition costs
– Impairment
– Abandonment
– Transfer to proved properties
Accounting for Acquisition and
Retention Costs – Full Cost Method
• Lease acquisition (CAPITALIZE DIRECT
ACQUISITION COSTS)
– Bonus payments, advance payments, options
• Retention Costs (CAPITALIZE RETENTION COSTS)
– Delay rentals, property taxes, defense costs, shut-in
royalties
• Disposition of capitalized acquisition costs
– Impairment and Abandonment
Impairment – Acquisition Costs
Successful Efforts and Full Cost
• Assess periodically (at least annually)
• Triggering Events include dry hole(s), little time left
on primary term, development not in the budget
• May amortize costs in a group of properties if
individually insignificant
Accounting Differences:
• Successful Efforts (FAS No 19) – impairment charged
to exploration expense
• Full Cost (SEC Reg. S-X 4-10) – impairment included
in the amortization base (full cost pool) and amortized
prospectively
AICPA Accounting
Standards Executive
Committee
Exploration and
Development Costs
Exploration Costs Defined
• Costs incurred to find proved reserves, including
identifying areas that may warrant examination,
examining specific areas, and drilling exploratory wells
and exploratory stratigraphic type test wells
• Costs may be incurred prior to obtaining the lease
• Include costs of:
– Carrying and retaining undeveloped properties
– Topographical or geophysical studies and salaries related to
these studies
Development Costs Defined
• Obtain access to proved reserves
• Provide facilities for extracting, treating, gathering, and
storing oil and gas
• All phases of drilling development wells (from preparing well
locations to placing on production) whether tangible (having
salvage value) or intangible (a tax term of not having salvage
value, such as making a hole)
• “Acquire, construct, and install production facilities such as
lease flow lines, separators, treaters, heaters, manifolds,
measuring devices, and production storage tanks, natural
gas cycling and processing plants, and utility and waste
disposal systems.”
• “Provide improved recovery systems”
Accounting for Exploration and
Development Costs
Exploration Costs
– Successful Efforts – Expense all exploration costs as
incurred, except those applicable to exploratory wells that
result in discovery of proved reserves (i.e. capitalize
successful exploratory wells and expense exploratory dry
holes)
– Full Costs – Capitalize
Development Costs
– Successful Efforts - Capitalize
– Full Cost - Capitalize
Exploration and Development Costs - Illustration
Site Well
D
1
Discovery, exploratory well establishes offset sites C and E as proved.*
E
2
Offset, development producing well. Well 2 proves Site F.*
F
3
Offset, development producing well. Assume data does not prove Site G.*
B
4
Step-out,exploratory producing well on unproved drill site. Assume data proves
Site A.
C
5
Offset, development producing well.
A
6
Offset, development dry hole. Costs remain capitalized as dev. costs. Well is
plugged.
G
7
Offset, exploratory dry hole. Costs are expensed (SE). Well is plugged.
*Proving a site means that geological and
engineering data indicate with reasonable
certainty that the site has sufficient
reserves to economically justify (at current
prices) drilling the site. Usually a
successful well and G&G data prove only
sites offsetting the successful well’s site.
The data may or may not prove all offset
locations.
Site
A
B
C
D
E
F
G
WELL
6
4
5
1
2
3
7
Gas Cap
Oil
Enchroaching Salt Water
What if . . .
Case 4-1: G&G Library
• What if a company buys a library of G&G data on many geographic
areas, with an estimated useful life of 3 years? Must the cost be
expensed under SE?
• Example: XYZ Co. pays $10,000 for seismic studies of undeveloped acreage in the
Gulf of Mexico
• The Rule [Oi5.109 aka FAS 19, par. 18 ]

“Geological and geophysical costs, costs of carrying and retaining undeveloped properties, and dry
hole and bottom hole contributions shall be charged to expense when incurred.”
• Guidance/Accounting

Seismic studies to enhance or evaluate development of a proved field may be capitalized as
development costs. If seismic study relates to exploration activities, expense as incurred. Seismic
related to both exploration and development activities should be allocated between development
costs (capitalized) and exploration costs (expensed). Full Cost companies capitalize all costs.
What if . . .
Case 4-2: Development / Exploratory Well
•
What if a development well is drilled below the proved
reservoir, looking for deeper reservoirs, yet unproven,
and finds no new reserves? Are the added costs
exploratory?
•
Example: XYZ Co. spends $1 million to access proved reserves
at 10,000 feet and continues down to another stratigraphic region,
spending another $400,000 to go to 15,000 feet, only to find no
proved reserves.
Rule [Oi5.401 aka FAS 19, par. 274 ]
•

Development
 A “development well is a well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be proved.”
•
Comment: A portion of a well (hole) can be a “development well” and
the remaining portion of the hole is an exploratory well for accounting
purposes.
Accounting for the example above
 Under Successful Efforts, XYZ expenses the $400,000 (spent to explore
below the proved horizon) as unsuccessful exploratory well costs and
capitalizes the $1 million as development costs.
10,000 ft,
Exploratory
15,000 ft,
What if . . .
Case 4-3: At first you don’t succeed…
• What if a twin (replacement) exploratory well is
needed? Are the costs of the abandoned first well
expensed as unsuccessful?

• Example: Drilling problems require XYZ Co. to stop short with
exploratory well #1, and immediately start over with a nearby “twin”
well which successfully discovers the reservoir. Is the $700,000
spent on well #1 unsuccessful exploration cost?
Successful
•
FAS 19 does not specifically address this case.
–
•
Arguably, it’s just another cost overrun of drilling “the well”.
Accounting for the example above
 Follow established accounting for such cases.
 Likely expense the $700,000.
Twin
Variations of Case 4-3
• Side tracking (preferable to expense the unsuccessful
costs)
• Producing well re-entered and drilled deeper (an
exploratory cost to be expensed if unsuccessful)
• Exploratory well finds no reserves at target formation,
drilling continues and discovers a deeper reservoir
(capitalize all costs as successful exploratory well)
• Exploratory well finds no reserves at target formation,
plugged back to shallower discovery (preferable to
expense the costs of drilling beyond the shallower
discovery).
• Exploratory well is a multi-lateral well
–
Wells can be described as vertical (traditional), directional, horizontal, or
multi-lateral
Side tracking
Multi-lateral well
What if . . .
Case 4-4: Well in Progress at End of
Reporting Period
•
•
What if an exploratory well is in-progress at year-end
whereby success cannot be determined at that time?
What if it’s found to be dry soon thereafter? Are costs
expensed as of period-end?
Example: XYZ Co. spent/accrued $400,000 for well in progress at
period-end. After period-end XYZ spent $200,000 more but found
no reserves. Deemed a dry hole prior to issuance of financial
• statements.
Rule [Oi5.130 / FAS 19, par 39 ] paraphrased:
–
•
Rule [Oi5.130 / FIN 36, par 2] paraphrased:
–
•
Use information available before financial statements are issued to
evaluate conditions at balance sheet date.
If such information indicates well was unsuccessful, expense costs as of
period-end, net of any salvage value
Accounting for the example above:
–
Expense the $400,000 as of period-end. Expense the $200,000 in the next
period (the period incurred).

Well in
progress at
year-end
?
AICPA Accounting
Standards Executive
Committee
Amortization of Proved
Property Costs
What is DD&A?
• Oil & gas property costs are “amortized” using a “unit
of production” method whereby. . .
– Amortization Base x production / beginning of year (BOY)
reserves = amortization expense
– $200,000 net book value x 10,000 bbls / 100,000 bbls =
$20,000 amortization
What is DD&A?, continued
Federal income tax law and regulations call for:
–“Depreciation” of capitalized well equipment cost (over a
stated life or on the unit of production basis),
–“Depletion” of capitalized property acquisition costs (on a unit
of production basis), and
–“Amortization” over 60 months of certain other costs, such as
intangible drilling costs that are not immediately deducted
Financial reporting (FAS No.19 and Regulation S-X
Rule 4-10) requires all costs be “amortized” on the unit
of production method
Amortization - Simple Example
• Amortization Base (NBV)
– Capitalized Costs, end of period
– Less prior accumulated amortization
$1,200,000
(200,000)
$1,000,000
• Production (quantity sold) for the period
• Oil & Gas reserves at period’s beginning:
– Latest reserve estimate (end of period)
– Add production for the period (above)
“Base”
30,000 bbls
270,000 bbls “R”
30,000 bbls “P”
300,000 bbls “R+P”
• Amortization = Base x P / (R +P) = $100,000
“P”
Calculating Amortization – Oil and Gas Produced
• What if both oil and gas are being produced? How is
amortization calculated?
• Example: Production (P) is 4,000 bbls and 6,000 mcf
•
•
Successful Efforts Rule (Oi5.129 / FAS 19, par 38) paraphrased:
Convert to common unit of measure [boe or mcfe] based on relative
energy content,but…
OK to use either oil or gas if it dominates or if P of oil to P of gas is
expected to remain relatively constant (answers about the same)
Full Cost Rule (Rule 4-10[c](3)(iii) paraphrased:
Same as for SE but allowed to use “gross revenue” method of P$/R$
Example solution:
4,000 bbl + 6,000 mcf x 1/6 = 5,000 boe; or
4,000 bbl x 6 + 6,000 mcf = 30,000 mcfe
Successful Efforts Amortization
• Costs grouped by field usually
• Field’s property acquisition costs amortized over total
proved reserves (developed and undeveloped)
• Field’s “well equipment and development” costs
(including IDC) amortized over proved developed
reserves (excluding undeveloped reserves)
What is a Field?
• Oi5.403 / FAS 19, par. 272
– “An area consisting of a single reservoir or multiple
reservoirs all grouped on or related to the same individual
geological structural feature or stratigraphic condition or
both.”
– Reservoirs may be separated laterally or vertically.
– Geological structure is not intended to include an entire
“basin”, “trend”, “play”, “area of interest”, etc.
– A reservoir is a “porous and permeable underground
formation containing a natural accumulation of producible oil
or gas . . . separate from other reservoirs.”
Developed vs. Undeveloped Proved Reserves
• Proved oil and gas reserves are
- estimated quantities which “geological and engineering data
demonstrate with reasonable certainty to be recoverable in the
future years from known reservoirs under existing economic
and operating conditions, i.e., prices and costs as of the date
the estimate is made.” (excerpt from SEC S-X Rule 4-10)
• Developed reserves are those expected to be
recovered through existing wells, using existing
equipment and operating methods
• Undeveloped reserves (PUDs) are those expected to
be recovered from:
- New wells on undrilled acreage, or
- Existing wells requiring major expenditure
Full Cost Amortization
Broader parameters for capitalized oil & gas costs
– Governed by SEC S-X Rule 4-10(c)
– Amortized costs are grouped by country, not field
– Amortization base includes all acquisition, exploration, and
development costs, including future development and
abandonment costs
• Includes company internal costs directly identified with
acquisition, exploration and development activities (not G&A or
production)
• Some costs may be temporarily excluded from amortization
– Amortized over total proved developed and proved
undeveloped reserves
AICPA Accounting
Standards Executive
Committee
Disposition of Oil & Gas
Assets
Dispositions - Successful Efforts
• Accounting - Successful Efforts
• General Rules:
– No gain if •
Pooling of assets in a joint venture
– No gain, but a loss may be recognized if •
Recovery of costs is in doubt or future performance is required
– Gain or loss if not described above
Dispositions – Full Cost
• Accounting - Full Cost
• General Rule:
– No gain or loss calculated
– Exception - Significantly alters the relationship between costs
and reserves
Sale of Entire Unproved Property
• Full Cost
– Credit proceeds to cost pool . . .
• Successful Efforts
– If impaired individually, recognize gain or loss
– If in an impairment group, no gain or loss recognition
• except to the extent sales price exceeds original cost
Sale of Part of an Unproved Property
• Full Cost
– Credit proceeds to cost pool . . .
• Successful Efforts
– Recovery of remaining cost is uncertain, so treat sales
proceeds as a recovery of cost…
– Except to the extent sales price exceeds
• original cost (if in an impairment group)
• carrying value net of impairment (if individually assessed for impairment)
Sale of Entire Proved Property
• Successful Efforts
– Recognize Gain or Loss
• Full Cost
– Credit sales proceeds to full cost pool
• unless DD&A rate significantly distorted (greater than 10%)
Sale of Part of a Proved Property (or
Amortization Group)
• Successful Efforts
– Recognize Gain or Loss
• Option: Do not recognize gain or loss (asset retirement) if amortization
rate not significantly changed
• No gain recognized if significant continuing involvement, however loss
may be recognized
• Apportion book value based on fair values
• Full Cost
– Credit sales proceeds to full cost pool
• unless DD&A rate significantly distorted (greater than 10%)
Example – Sale of Part of a Proved
Property – No continuing
involvement
XYZ Company sells half of a 2% ORRI in a proved property with
a NBV of $10,000 for $1 million.
– Rule: Oi5.138(j) [FAS 19 par. 47j]: Recognize gain or loss.
Allocate cost between portion sold and portion retained on the
basis of fair values.
– Accounting: [selling 50%, FV of sold = FV of retained]
Cash
$1,000,000
Proved property costs [$10,000 x 50%]
$5,000
Gain on sale
$995,000
Example – Sale of Part of a Proved
Property – Continuing involvement
XYZ Company sells a 10% ORRI carved from a working interest
on proved property with a NBV of $100,000 and a remaining FV
of $120,000 for $40,000.
– Rule: Oi5.136(b), .138(j), .138(k), & .138(a): May recognize loss,
but no gain. .138(j): Calculate using relative fair values
– Accounting:
•
•
Gain or loss? $100m x [40m / (40m + 120m)] = $25m cost
$40m proceeds - $25m cost = $15m gain. Do not recognize.
Cash
$40,000
Property cost
$40,000
AICPA Accounting
Standards Executive
Committee
Impairment of Oil & Gas
Assets
General Rules – Comparison Between Successful Efforts and Full Cost
Element
Successful Efforts
Full Cost
•
Authoritative Guidance
•
FAS No. 144
•
Regulation S-X 4-10
•
Performance Criteria
•
Trigger event
•
Quarterly
•
Price and Cost
Assumptions
•
Management’s internal
pricing
•
Constant (based on year end
prices)
•
Grouping
•
Usually field-level
•
Country by country
•
Property Types
•
Proved properties only
•
Proved properties only
•
Income Tax
Considerations
•
Typically excluded
•
Included
•
Component of Income from •
continuing operations
presented either separately
or disclosed in notes
•
Presentation and
Disclosure
Component of Income from
continuing operations
presented either separately
or disclosed in notes
General Impairment Rules
Property
Type
Successful Efforts
Full - Cost
•
Proved
•
SFAS 144
•
S-X 4-10(C)(4) “Ceiling Test” - If
country-wide costs less deferred
taxes exceed discounted after-tax
cash flows at current pricing (plus
costs not being amortized), writeoff excess
•
Unproved
•
FAS No. 19 and S-X 4-10;
judgmental, systematic
amortization, based on lease
terms, dry holes, and drilling
intent
•
S-X 4-10(C)(3)(II)(1) and (C)(4)
“Asset Impairment” as for
successful efforts and reclassify
impairment to amortization base
(reducing ceiling)
Assessing Impairment – Step 1
• Assess impairment when events or circumstances
indicate the asset carrying amount may not be
recoverable.
• Usually quarterly because mere passage of time is an
indicator.
• Types of “Trigger Events”:
•
•
•
•
•
•
Passage of time
Decrease in prices
Higher than anticipated development costs
Decrease in reserve estimates (“downward revisions”)
Environmental issues
Adverse political; legislative; or regulatory changes
Assessing Impairment - Step 2
• Compare carrying amount to undiscounted,
expected future cash flows (UEFCF)
• If carrying amount exceeds UEFCF, go to Step 3.
Assessing Impairment - Step 3
• Write off carrying amount in excess of fair value
• No requirement to get an appraisal
• No specific guidance in determining FV
• Usually fair value reflects discounted, expected future
cash flows
• Discount rate is usually greater than 10% when
applied to truly expected future cash flows
Example FAS No. 144 Impairment Analysis for
Proved Properties
Step 1 -
Assumed occurrence of trigger event
Determination of NBV
Step 2 Comparison
against
undiscounted
cash flow
Capitalized cost of proved properties
Accumulated DD&A
Liability for plugging & abandonment
$ 5
nil
Net book value
Recognition test
Future UEFCF before taxes
Impairment loss
Step 3 Measurement
of impairment
Field A
$4
Measurement of impairment
Fair value (Discounted Expected Future Cash Flows)
Impairment
Field B
Field C
$ 20
(2)
(2)
$10
(8)
(1)
$ 3
$ 10
$ 6
$ 8
no
$8
yes
no
(5)
$ 5
(3)
Full Cost Ceiling Test
CEILING COMPONENTS:
• Present value of of future cash flows from proved reserves
–
–
–
–
Current sales prices and cost rates as of the balance sheet date
Proved reserves (no probable or possible reserves)
Future revenues less (operating, development, and P&A) costs
Future net revenues are discounted at 10% per annum
• Current capitalized costs of properties not amortized
– Cost of unproved properties not being amortized
– Cost of unusually significant development projects not being
amortized
Full Cost Ceiling Test
CEILING COMPONENTS (continued)
• Lower of cost or fair value of unproved properties
amortized
– Usually zero if unproved properties are excluded from amortization
since impaired costs moving into amortization base have a fair
value of zero
• Income tax effects of the first three components
– Exemptions for purchased property and favorable events prior to
auditor’s report
Full Cost Ceiling Test - Other Topics
• Ceiling Test Exemption for Proved Purchased Property:
– SAB Topic 12D, Question 3: Explains how ASR 258 ceiling exemption
can be obtained
– Request temporary waiver from SEC
– Registrant requesting waiver should be prepared to demonstrate the
additional value exists beyond a reasonable doubt
• Subsequent Events:
– SAB Topic 12D, Question 3
– Ceiling test write-down avoided if:
• Additional proved reserves added before audit report
• Price increases become known before audit report
AICPA Accounting
Standards Executive
Committee
FAS No. 143 - Asset
Retirement Obligations
FAS No. 143 - Overview
• Obligations of an entity that are unavoidable as a
result of the acquisition, construction or the normal
operation of a tangible long-lived asset
• Designed to end diversity in practice
• Retirement obligation (liability) recognized when
incurred
• Fair value method of calculating liability
• Retirement costs are capitalized (and depreciated)
FAS No. 143 – Qualifying Obligations
Qualifying Obligations:
• Dismantlement of offshore platform
• Plugging and abandonment of oil and gas well bores
• Production facilities
• Underground storage facilities
• Distribution and transmission assets
• Others. . .
FAS No. 143 – Full Cost Implications
•
Impact on the Full Cost Ceiling Test
•
•
•
Asset retirement costs are recorded in the full cost pool and subject to
ceiling limitation; when calculating the ceiling, ARO (abandonment
obligation) is deducted from future cash flows, resulting in “double
counting”
SAB 106 requires companies to exclude abandonment obligation from
future cash flow analysis
Impact on DD&A calculation related to future asset
retirement costs expected to result from future
development activities
•
SAB 106 provides that companies must estimate the asset retirement
costs associated with future development activities (for ARC not
recorded in the balance sheet)
AICPA Accounting
Standards Executive
Committee
Oil & Gas Revenues and
Production Costs
Determinants of Revenue
• Ownership
• Volumes
• Prices
Ownership
• Division Order
– Contract between all of the owners of an oil and gas
property and the company purchasing production from the
property.
– Sets forth the interest of each owner and serves as the basis
on which the purchasing company pays each owner’s
respective share of the proceeds of the oil and gas
purchased.
Ownership - Example
Working interest (WI): Cost Sharing
Net revenue interest (NRI): Revenue
Sharing
Example:
WI
NRI
E&P, Inc.
60%
51%
Mee2 oil and gas
40%
34%
Geologist (ORRI)
0%
2.5%
Lessor (royalty, RI)
0%
12.5%
100%
100%
Volumes
Oil
BBL - barrels (42 gallons)
Gas
MCF - thousand cubic feet
-
MMCF - million cubic feet
-
BCF - billion cubic meet
•
Gas may also be expressed in heat quantity (Btu or MMBtu)
rather than volume
•
Ratio of MMBtu to Mcf varies from 1:1 to 1.3:1. The wetter the
gas, the higher the ratio.
Volumes
• Oil Volumes
– Stored In “Lease Tanks" at the field until enough
accumulated to sell
• Gas Volumes
– Produced into a pipeline or gathering system
– Often sold downstream, out of a pipeline or processing plant
(pipelines usually act as transporters, not purchasers)
– Meters (pipeline meter and operator's check meter) measure
volume movement
– Lease-use gas and shrinkage
Oil Prices
•
Evergreen contract tied to posted price bulletins
•
Price may also be
- Fixed
- New York mercantile exchange futures (NYMEX)
- Other indices
•
Bulletin's pricing determinants:
- Geographic location
- Date of sale
- Sulfur content (i.e., sweet or sour)
- Density (API gravity)
Gas Prices
• Typically per MMBTU
• Marketing charges
- Gathering
- Dehydration
- Processing
- Transportation
- Marketing fees
- Pipeline capacity reservation
- Storage
- Hub services (banking)
• Sales points
Production Costs (aka Lease
Operating Expense)
• Definition - Costs incurred to operate and maintain
wells and related equipment and facilities, including
depreciation and applicable operating costs of
support equipment and facilities and other costs of
operating and maintaining those wells and related
equipment and facilities (SX Rule 4-10(a)(17))
Types of Production Costs
• Direct Production Costs
–
–
–
–
–
Salaries and wages, including related employee benefits
Contract pumping services
Well services and workover
Repairs and maintenance of surface equipment
Ad Valorem (property), production and severance taxes
• Indirect Production Costs
– Depreciation of support facilities
– Salt water disposal
Accounting for Production Costs
• Expensed as incurred, except
– Recording oil and gas inventory at cost
– Workover costs that qualify for capitalization
Workover Costs
• Expense
– Costs to restore or maintain production
– Increases production
• Capitalize
– Costs to explore to an unproved formation
– Costs to access a proved formation
– Increases reserves
AICPA Accounting
Standards Executive
Committee
Joint Interest Billing
Joint Venture – Defined
• An association of two or more persons or companies
to drill, develop, and operate jointly owned properties.
Each owner has an undivided interest in the
properties.
Why Joint Operations?
• Companies desire to share the risk and high costs involved
in exploration and development
• Economic sense
• Necessity
• Secondary or tertiary recovery techniques
Joint Operations - Overview
• Joint ventures are common in the industry, therefore,
joint interest billing (JIB) systems are essential
• Agreements
– Joint venture agreement
• Who is in what venture?
– Joint operating agreement (JOA)
• Designates an operator (others are non-operators)
• Rules for going “non-consent”
– JOA’s accounting exhibit
• Billing and audit protocol
Joint Operations - Overview
• JIB system
– Operator obtains partners’ approvals for major costs (using
an authorization for expenditure “AFE”)
– Operator billed for venture costs and bills its partners for their
share
– Operator records its net share
– Operator pays venture’s costs and bills partners their share
– Most JOAs allow partners (non-operators) to audit the
operator’s billings within two years of the related
expenditures
Joint Operating Agreement
JOA provides:
• Parties’ interests in costs (working interest “WI”) and production
(Net revenue interest “NRI”)
• Operator
– Designation, removal
– Rights and duties
• Protocol for joint venture conducting drilling and development
– Initial well
– Deepening, sidetracking, completion, reworking, recompleting,
plugging back and abandoning wells
– Non-consent provisions
• Taking production in kind
Joint Operating Agreement
• Gas balancing
– Gas balancing agreement (GBA)
• Operator’s remedies for failure of non-operator to pay
– Pay and take over interest
– Have rest of JV pay and take over interest
– Net billings against revenues
• Election to not be a partnership for income tax purposes
• Insurance to be carried by operator
• Sharing of costs for suits against the joint venture
JOA Accounting
• Operator bills non-operators monthly
– By AFE, lease, or project
– Sufficient detail for financial & tax accounting
– May bill in advance, major approved projects (“cash calls”)
• Non-operators allowed two years after billing date to
challenge paid billings.
– Conduct expenditure audit to uncover and substantiate
adjustments
– Adjustments argued and negotiated
JOA Accounting
• Operator bills for:
–
–
–
–
–
Direct charges
Operator’s employees directly employed
Materials
Use of operator’s equipment and facilities
Overhead recovery (determined by COPAS)
•
At a fixed rate (e.g. $3,000/mo/drilled well and
$300/mo/producing well), adjusted for inflation annually using
escalation factors; or
•
At a percentage of direct costs
AICPA Accounting
Standards Executive
Committee
Oil & Gas Reserves and
Related Disclosures
Oil & Gas Reserve Classifications
• Society of Petroleum Engineers defines reserves as
discovered and recoverable
– Proved (“reasonably certain” - 90% probability)
• Developed
• Undeveloped
– Unproved
• Probable (“likely” - as in 51% to 90% probability)
• Possible (“reasonably possible” - less than likely)
Proved Reserves
• Proved oil and gas reserves
 Estimated quantities which “geological and engineering data
demonstrate with reasonable certainty to be recoverable in
the future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as
of the date the estimate is made.” (excerpt from SEC S-X
Rule 4-10)
Proved Reserves – Developed vs.
Undeveloped
• Developed reserves:
– Expected to be recovered through existing wells, using
existing equipment and operating methods
• Undeveloped reserves:
– Expected to be recovered from
- New wells on undrilled acreage; or
- Existing wells requiring major expenditure
Key Definitions
• Economically Recoverable:
– Reserves that can be extracted from reservoir and delivered to market
in an economically beneficial way to the producing entity
• Shut-in:
– Reserves expected to be recovered from completion intervals that
were open at the time of the reserve estimate but are not producing
• Behind pipe:
– Reserves expected to be recovered from completion interval(s) not yet
open but still behind casing in existing wells. Such wells are usually
producing, but from another completion interval. Additional completion
work is needed before these reserves are produced.
Determination of Oil & Gas Reserve
Quantities
• Estimates may be performed internally
• Estimates may be performed internally and data
reviewed or audited by external engineer based on
Standards Pertaining to the Estimating and Auditing
of Oil and Gas Reserve Information by the Society of
Petroleum Engineers
• Estimates may be performed externally with certain
data provided by the oil and gas company
Reserve Estimation and Valuation Process
Data Points
Technical
Economic
• Porosity
• Proved determination
• Permeability
• Year end pricing
• Gas to liquids ratio
• Historical lifting costs
• Product quality
/characteristics
• Future development costs
• Well logs
• Seismic data
• Interpretations
• Decline curves
• Feasibility
assumptions
Reserve Volume
and SMOG
Value Calculations
• Future abandonment
costs/ reclamation costs
• Production/severance tax
rates
Transactional
• Historical production volumes
• Recovery techniques
• New well/property sale/property
abandonment/property
purchase
• PZ factor
• Division orders/title opinions
• Curtailments/shut-ins
• Net profit interests
• Payouts/reversionary interests
• Take-or-pay
Reserve
Quantity
Information
SMOG
Is Disclosure of Oil & Gas Reserve
Information Required?
Disclosure required for “significant” oil and gas producing
activities if O&G activities are at least 10% of company’s total
activities, based on any one of the following ratios:
– Revenues from oil and gas > 10% of combined revenues of all
segments
– Identifiable assets of oil and gas activities > 10% of the assets,
excluding assets used exclusively for general corporate purposes
– Results of operations of oil and gas activities > 10% of the larger of:
(a) Combined operating profit or all industry segments that did not incur an
operating loss; or
(b) Combined operating loss of all industry segments that did incur an
operating loss
Supplemental Disclosures Required
by FAS No. 69
–
–
–
–
–
Capitalized costs
Costs incurred
Results of operations for oil & gas related activities
Proved reserves and changes in proved reserves
Standardized Measure of Discounted Future Net Cash Flows
(SMOG) and related changes therein
– Special disclosures for companies using full cost
– Disclosures only for PROVED oil and gas reserves
SMOG Overview
• FAS 69 requires disclosure of “a standardized measure of
discounted future net cash flows relating to proved O&G reserve
quantities
• Intended to be a comparative benchmark tool
• SMOG disclosures:
– Required for publicly traded oil and gas companies
– Must be disclosed in aggregate
– Must be disclosed for each geographic area for which reserve
quantities are disclosed
– Changes in SMOG also must be disclosed
AICPA Accounting
Standards Executive
Committee
Other Property
Conveyances
Property Conveyance Types
• 4 Types
–
–
–
–
Loan
Prepaid Commodity Sale
Volume Production Payment (VPP)
Outright Sale
What is a Borrowing? What is a Sale?
Loan
Prepaid
commodity sale
Volumetric
Prod. Pmt.
Outright Sale
Who assumes
production risks
“Seller” (cash
recipient)
Who assumes
pricing risks
“Seller” (cash
recipient)
Seller
Buyer
Buyer, mostly
Buyer
Buyer
Buyer
What is a Borrowing? What is a Sale?
• Loan - borrowings are repaid usually through money
received from production
• Prepaid - borrowings are repaid through volumes of
production. Seller must make up short fall
• VPP - same as Prepaid except there is no obligation to
make up short fall
• Outright Sale - buyer assumes all risk
Special Cases
• Production Payment: Conveyor’s obligation to pay –
(holder’s right to receive) specified cash or deliver
specified production from specified production only
– If specified cash, production payment is conveyor’s payable (loan)
and holder’s receivable
– If specified quantity, the Volumetric Production Payment (VPP) is a
mineral interest sale but proceeds received are credited as deferred
revenue.
• Prepaid: Conveyor’s obligation to deliver specified
quantity (no required source)
Volumetric Production Payment
(VPP) Accounting
• Full Cost:
– SX Rule 4-10c(6i) literally says credit the full cost pool (The
VPP is a sale).
– Off-balance sheet financing
• Successful Efforts:
– FAS 19, par. 47(a) says to treat as unearned revenue to be
recognized as the oil and gas is delivered.
– EITF 88-18 states that these financing arrangements are
advances for future production and should be classified as
debt unless conditions justify otherwise.
Volumetric Production Payment
(VPP) Accounting
• Both credit deferred revenue
• VPP is sale of a mineral interest. Conveyor sells
reserves to holder.
• Prepaid is NOT a sale of a mineral interest but
prepayment for future sale of oil or gas. Conveyor
sells no reserves to holder.
Volumetric Production Payment (VPP)
• Sale. No gain recognition; seller has substantial future
obligation (disproportionate LOE burden + delivery
obligation)
• Buyer has oil and gas reserves. UOP amortization of
property cost.
• Seller records deferred revenue! Not deferred gain.