Accounting for specific industry-Oil and gas accounting

Pertemuan 23-24

Mata kuliah : F0074 - Akuntansi Keuangan Lanjutan IITahun : 2010

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Oil and Gas Accounting Oil and Gas Accounting Background and Accounting Background and Accounting

MethodsMethods

Oil & Gas Accounting BackgroundOil & 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 MethodsTwo Types of Accounting Methods• FULL COST - Basic Concept

– All costs associated with property acquisition, exploration and development activities shall be capitalized by country-wide 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.

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Acquisition and Retention Acquisition and Retention CostsCosts

Acquisition and Retention CostsAcquisition 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 AgreementThe Lease AgreementMineral 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 InterestsTypes 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 Accounting for Acquisition and Retention Costs – Successful Retention Costs – Successful

Efforts MethodEfforts 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 Accounting for Acquisition and Retention Costs – Full Cost Retention Costs – Full Cost

MethodMethod

• 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 CostsImpairment – Acquisition CostsSuccessful Efforts and Full CostSuccessful 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

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Exploration and Exploration and Development CostsDevelopment Costs

Exploration Costs DefinedExploration 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 DefinedDevelopment 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 Accounting for Exploration and Development CostsDevelopment 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 - IllustrationExploration and Development Costs - IllustrationSite 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

Oil

Gas Cap

Enchroaching Salt Water

What if . . . What if . . . Case 4-1: G&G LibraryCase 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 . . . What if . . . Case 4-2: Development / Exploratory WellCase 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.

10,000 ft,

Development

15,000 ft,

Exploratory

• Rule [Oi5.401 aka FAS 19, par. 274 ] 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.

What if . . . What if . . . Case 4-3: At first you don’t succeed…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

Twin

• 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.

Variations of Case 4-3Variations 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 . . . What if . . . Case 4-4: Well in Progress at End of Case 4-4: Well in Progress at End of

Reporting PeriodReporting 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. Well in

progress at year-end

• Rule [Oi5.130 / FAS 19, par 39 ] paraphrased:– Use information available before financial statements are issued

to evaluate conditions at balance sheet date.

• Rule [Oi5.130 / FIN 36, par 2] paraphrased:– 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).

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Amortization of Proved Amortization of Proved Property CostsProperty Costs

What is DD&A?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?, continuedWhat is DD&A?, continuedFederal 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 ExampleAmortization - Simple Example• Amortization Base (NBV)

– Capitalized Costs, end of period $1,200,000– Less prior accumulated amortization (200,000) $1,000,000

“Base”

• Production (quantity sold) for the period 30,000 bbls “P”

• Oil & Gas reserves at period’s beginning:– Latest reserve estimate (end of period) 270,000 bbls “R”– Add production for the period (above) 30,000 bbls “P”

300,000 bbls “R+P”

• Amortization = Base x P / (R +P) = $100,000

Calculating Amortization – Oil and Gas ProducedCalculating 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 AmortizationSuccessful 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?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 AmortizationFull Cost AmortizationBroader 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

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Disposition of Oil & Gas Disposition of Oil & Gas AssetsAssets

• 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 - Successful Efforts Dispositions - Successful Efforts

Dispositions – Full CostDispositions – 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 PropertySale 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 PropertySale 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 PropertySale 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 Sale of Part of a Proved Property (or Amortization Property (or Amortization

Group)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 Example – Sale of Part of a Proved Property – No continuing Proved Property – No continuing

involvementinvolvement

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 Example – Sale of Part of a Proved Property – Continuing Proved Property – Continuing

involvementinvolvement

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

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Impairment of Oil & Gas Impairment of Oil & Gas AssetsAssets

General Rules – Comparison Between Successful Efforts and Full Cost

• Regulation S-X 4-10

• Quarterly

• Constant (based on year end prices)

• Country by country

• Proved properties only

• Included

• Component of Income from continuing operations presented either separately or disclosed in notes

Successful Efforts Full CostElement

• FAS No. 144

• Trigger event

• Management’s internal pricing

• Usually field-level

• Proved properties only

• Typically excluded

• Component of Income from continuing operations presented either separately or disclosed in notes

• Authoritative Guidance

• Performance Criteria

• Price and Cost Assumptions

• Grouping

• Property Types

• Income Tax Considerations

• Presentation and Disclosure

General Impairment Rules

• 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), write-off excess

Successful Efforts Full - Cost

• Proved

Property Type

• 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

Determination of NBV Field A Field B Field C

Capitalized cost of proved properties $ 5 $ 20 $10

Accumulated DD&A (2) (8) (3)

Liability for plugging & abandonment nil (2) (1)

Net book value $ 3 $ 10 $ 6

Step 1 - Assumed occurrence of trigger event

Step 2 - Comparison against undiscounted cash flow

Step 3 - Measurement of impairment

Measurement of impairment

Fair value (Discounted Expected Future Cash Flows) (5)

Impairment $ 5

Recognition test

Future UEFCF before taxes $ 4 $ 8 $ 8

Impairment loss no yes no

Full Cost Ceiling TestCEILING 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 TestCEILING 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

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FAS No. 143 - Asset FAS No. 143 - Asset Retirement ObligationsRetirement 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 ObligationsQualifying 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)

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Oil & Gas Revenues and Oil & Gas Revenues and Production CostsProduction 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 - ExampleWorking 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%

VolumesOil 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

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Joint Interest BillingJoint 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 AgreementJOA 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

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Oil & Gas Reserves and Oil & Gas Reserves and Related DisclosuresRelated 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

Technical

• Porosity

• Permeability

• Gas to liquids ratio

• Product quality /characteristics

• Well logs

• Seismic data

• Interpretations

• Decline curves

• Feasibility assumptions

• Recovery techniques

• PZ factor

Transactional

• Historical production volumes

• New well/property sale/property abandonment/property purchase

• Division orders/title opinions

• Curtailments/shut-ins

• Net profit interests

• Payouts/reversionary interests

• Take-or-pay

Economic

• Proved determination

• Year end pricing

• Historical lifting costs

• Future development costs

• Future abandonment costs/ reclamation costs

• Production/severance tax rates

Reserve Quantity

Information

SMOG

Data Points

Reserve Volume and SMOG

Value Calculations

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 AICPA Accounting Standards Executive Standards Executive

CommitteeCommittee

Other Property Other Property ConveyancesConveyances

• 4 Types– Loan– Prepaid Commodity Sale– Volume Production Payment (VPP)– Outright Sale

Property Conveyance Types

What is a Borrowing? What is a Sale? Who assumes

production risks Who assumes pricing risks

Loan “Seller” (cash recipient)

“Seller” (cash recipient)

Prepaid commodity sale

Seller

Buyer

Volumetric Prod. Pmt.

Buyer, mostly

Buyer

Outright Sale

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.

• 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) Accounting

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.