ninth edition accountants’ handbook · 2020. 8. 16. · volume one: financial accounting and...

Ninth Edition

ACCOUNTANTS’HANDBOOK

VOLUME TWO:Special Industriesand Special Topics

SUBSCRIPTION NOTICE

This Wiley product is updated on a periodic basis with supplements to reflect importantchanges in the subject matter. If you purchased this product directly f rom John Wiley & Sons,Inc., we have al ready recorded your subscription for this update service.

If, however, you purchased this product from a bookstore and wish to receive (1) the currentupdate at no additional charge, and (2) future updates and revised or related volumes bil ledseparately with a 30-day examination review, please send your name, company name (if ap-pl icable), address, and the ti tle of the product to:

Supplement DepartmentJohn Wiley & Sons, Inc.One Wiley DriveSomerset, NJ 088751-800-225-5945

For customers outside the United States, please contact the Wiley of f ice nearest you:

Professional & Reference Division John Wiley & Sons, Ltd.John Wiley & Sons Canada, Ltd. Baf f ins Lane22 Worcester Road ChichesterRexdale, Ontario M9W 1L1 West Sussex, PO19 1UDCANADA UNITED KINGDOM(416) 675-3580 (44) (243) 7797771-800-567-4797FAX (416) 675-6599

Jacaranda Wiley Ltd. John Wiley & Sons (SEA) Pte. Ltd.PRT Division 37 Jalan PemimpinP.O. Box 174 Block B #05-04North Ryde, NSW 2113 Union Industrial BuildingAUSTRALI A SINGAPORE 2057(02) 805-1100 (65) 258-1157FAX (02) 805-1597

Ninth Edition

ACCOUNTANTS’HANDBOOK

VOLUME TWO:Special Industries and Special Topics

D.R. CarmichaelSteven B. LilienMartin Mellman

JOHN WILEY & SONS, INC.New York • Chichester • Weinheim • Brisbane • Singapore • Toronto

PostScript Picture

WILEY.EPS

This book is printed on acid-free paper.

Copyright © 1999 by John Wiley & Sons, Inc. Al l r ights reserved.

Publ ished simultaneously in Canada.

No part of this publ ication may be reproduced, stored in a retrieval system or transmitted in any form or by any means, electronic, mechanical, photocopying, recording, scanning or otherwise, except as permitted under Section 107 or 108 of the 1976 Uni ted States Copyright Act, without ei ther the prior wri tten permission of the Publ isher, or authorization through payment of theappropriate per-copy fee to the Copyright Clearance Center, 222 Rosewood Drive, Danvers, MA 01923, (978) 750-8400, fax (978) 750-4744. Requests to the Publ isher for permission should beaddressed to the Permissions Department, John Wiley & Sons, Inc., 605 Third Avenue, New York, NY 10158-0012, (212) 850-6011, fax (212) 850-6008, E-Mail: PERMREQ @WILEY.COM.

This publ ication is designed to provide accurate and authori tative information in regard to the subject matter covered. It is sold with the understanding that the publ isher is not engaged in rendering legal, accounting, or other professional services. If legal advice or other expert assistance is required, the services of a competent professional person should be sought.

Library of Congress Cataloging-in-Publ i cation Data:

Accountants’ handbook / [edi ted by] D.R. Carmichael, Steven B. Li l ien,Martin Mellman. — 9th ed.

p. cm.Includes bibl iographical references and index.Contents: v. 1. Financial accounting and general topics — v.

2. Special industries and special topics.ISBN 0-471-29122-6 (pa. : set : alk. paper). — ISBN 0-471-29594-9

(pa. : vol. 1 : alk. paper). — ISBN 0-471-29595-7 (pa. : vol. 2 :alk. paper)

1. Accounting—Encyclopedias. 2. Accounting—Handbooks, manuals,etc. I. Carmichael, D. R. (Douglas R.), 1941– . I I. Li l ien,Steven B. I I I. Mellman, Martin.HF5621.A22 1999657—dc21 98-39840

Printed in the Uni ted States of America

10 9 8 7 6 5 4 3 2 1

v

CONTENTS

VOLUM E ONE: FI NANCI AL A CCOUNTI NG AND GENERAL TOPIC S

1 The Fr amework of Fi nancial Account ing Concepts and Standar dsREED K. STOREY, PhD, CPAFinancial Accounting Standards Board

2 Financial Account ing Regulat ions and OrganizationsPAUL B. W. MILLER, PhD, CPAUniversity of Colorado at Colorado Spr ings

3 SEC Report ing RequirementsDEBRA J. MACLAUGHLIN, CPABDO Seidman LLPWENDY HAMBLETON, CPABDO Seidman LLP

4 Management Discussion and AnalysisSTEPHEN BRYAN, MBA, PhDThe Stan Ross Department of Accountancy, Zicklin School of Business, Bernard M. Baruch College, CUNY

5 I nternational Account ing and Standar dsANTHONY N. DALESSIO, CPAKPMG Peat Marwick LLPMONA E. SEILER, CPAQueensborough Community College,The City University of New YorkRICHARD C. JONES

Hofstra University

6 Financial Statements: Form and ContentJAN R. WILLIAMS , PhD, CPACollege of Business Administration,University of Tennessee

7 I ncome Statement Presentation and Ear nings per ShareIRWIN GOLDBERG, CPAVornado Realty Trust

8 Account ing for Business CombinationsPAUL PACTER, PhD, CPAInternational Accounting Standards Committee

vi CONTENTS

9 Consolidation, Tr anslation, and the Equity MethodSTEVEN RUBIN, CPAWeissbar th, Altman & Michaelson LLP, CPAs and Consultants

10 Statement of Cash FlowsMONA E. SEILER, CPAQueensborough Community College,City University of New York

11 I nterim Financial StatementsANTHONY J. MOTTOLA, CPAMottola & Associates, Inc.

12 Analyzing Financial StatementsGERALD I. WHITE, CFAGrace & White, Inc.ASHWINPAUL C. SONDHI, PhDA. C. Sondhi and Associates, LLC

13 Cash and I nvestmentsLUIS E. CABRERA, CPAAmer ican Institute of Cer ti fied Public Accountants

14 Revenues and ReceivablesHENRY R. JAENICKE, PhD, CPADrexel University

15 I nventoryALEX T. ARCADY, CPAErnst & Young LLPRICHARD L. RODGERS, CPAErnst & Young LLP

16 Property, Plant , Equipment , and DepreciationALEX T. ARCADY, CPAErnst & Young LLPCRAIG STONE, CPAErnst & Young LLP

17 I ntangible AssetsLAILANI MOODY, CPA, MBAGrant Thor ton LLP

18 LeasesJAMES R. ADLER, PhD, CPACheckers, Simon & Rosner LLP

CONTENTS vii

19 Account ing for I ncome TaxesE. RAYMOND SIMPSON, CPAFinancial Accounting Standards Board

20 Li abi l i t iesMARTIN MELLMAN , PhD, CPAProfessor Emer itus,The Stan Ross Department of Accountancy, Zicklin School of Business,Bernard M. Baruch College, CUNYSTEVEN B. LILIEN, PhD, CPAChair man and the Weinstein Professor of Accountancy,The Stan Ross Department of Accountancy, Zicklin School of Business,Bernard M. Baruch College, CUNY

21 Derivatives and Hedge Account ingROBERT H. HERZ, CPA, FCAPricewaterhouseCoopers LLPBHASKAR (BOB) H. BHAVE, MBA, CPA, CMAPricewaterhouseCoopers LLPSTEPHEN BRYAN, MBA, PhDThe Stan Ross Department of Accountancy, Zicklin School of Business,Bernard M. Baruch College, CUNY

22 Shareholders’ EquityMARTIN BENIS, PhD, CPAThe Stan Ross Department of Accountancy, Zicklin School of Business,Bernard M. Baruch College, CUNY

23 Audit ing Standar ds and Audit ReportsDAN M. GUY, PhD, CPAALAN J. WINTERS, PhD, CPAClemson UniversityKIM GIBSON, CPAAmer ican Institute of Cer ti fied Public Accountants

VOLUM E TWO: SPECIALI ZED I NDUSTRI ES AND SPECIAL TOPIC S

24 Oi l, Gas, and Other Natur al ResourcesRICHARD P. GRAFF, CPAPricewaterhouseCoopers LLPJOSEPHB. FEITEN, CPAPricewaterhouseCoopers LLP

25 Real Estate and Constr uct ionGEORGEPATTERSON, CPAErnst & Young LLP

viii CONTENTS

26 Financial I nst i tut ionsWILLIAM J. LEWIS, CPALINDA K. SEITZ, CPAMICHAEL A. SEELIG, CPAJONATHON MARTIN, CPATHOMAS J. ROMEO, CPAGARY C. MELTZER, CPAMARY B. HEATH, CPAKENNETH W. BUSEY, CPAPricewaterhouseCoopers LLP

27 Regulated Uti l i t iesBENJAMIN A. MCKNIGHT III, CPAArthur Andersen LLP

28 State and Local Government Account ingANDREW J. BLOSSOM, CPAKPMG Peat Marwick LLPANDREW F. GOTTSCHALK, CPAKPMG Peat Marwick LLPJOHN R. MILLER, CPA, CGFMKPMG Peat Marwick LLPWARREN RUPPEL, CPADiTommaso & Ruppel, CPAs

29 Not-for-Prof i t Or ganizationsRICHARD F. LARKIN, CPAPricewaterhouseCoopers LLP

30 Providers of Health Care ServicesMARTHA GARNER, CPAPricewaterhouseCoopers LLPWOODRIN GROSSMAN, CPAPricewaterhouseCoopers LLP

31 Account ing for Government Contr actsMARGARET M. WORTHINGTON, CPAPricewaterhouseCoopers LLP

32 Pension Plans and Other Postret i rement and Postemployment Benef i tsVINCENT AMOROSO, FSAKPMG Peat Marwick LLPPAUL C. WIRTH, CPAKPMG Peat Marwick LLP

33 Stock-Based CompensationPETER T. CHINGOS, CPAKPMG Peat Marwick LLPWALTER T. CONN, JR., CPAKPMG Peat Marwick LLPJOHN R. DEMING, CPAKPMG Peat Marwick LLP

CONTENTS ix

34 Prospect ive Financial StatementsDON M. PALLAIS , CPA

35 Personal Fi nancial StatementsTHOMAS D. HUBBARD, PhD, CPA, CFEUniversity of Nebraska, LincolnDENNIS S. NEIER, CPAGoldstein Golub Kessler & Company, P.C.

36 Par tnerships and Joint VenturesGERARD L. YARNALL , CPADeloit te & Touche, LLPGEORGEN. DIETZ, CPAAmer ican Institute of Cer ti fied Public AccountantsRONALD J. PATTEN, PhD, CPADePaul University

37 Estates and Tr ustsPHILIP M. HERR, JD, CPAKingsbridge Financial Group, Inc.

38 Valuation of Nonpubl ic CompaniesALLYN A. JOYCE

Allyn A. Joyce & Co., Inc.JACOB P. ROOSMA, CPADeloit te & Touche LLP

39 Bankr uptcyGRANT W. NEWTON, PhD, CPA, CMAPepperdine University

40 Forensic Account ing and Li t igation Consult ing ServicesJEFFREY H. KINRICH, CPAPricewaterhouseCoopers LLPM. FREDDIE REISS, CPAPricewaterhouseCoopers LLPELO R. KABE, CPAPricewaterhouseCoopers LLP

I ndex

24 • 1

CHAPTER 24OIL, GAS, AND OTHERNATURAL RESOURCES

Richard P. Graff, CPAPricewaterhouseCoopers LLP

Joseph B. Feiten, CPAPricewaterhouseCoopers LLP

CONTENTS

24.1 INTRODUCTION 2

24.2 OIL AND GAS EXPLORATIONAND PRODUCING OPERATIONS 2

24.3 ACCOUNTING FOR JOINTOPERATIONS 4

(a) Operator Accounting 4(b) Nonoperator Accounting 5(c) Other Accounting Procedures 5(d) Overview of Accounting

Standards 5

24.4 ACCEPTABLE ACCOUNTINGMETHODS 6

(a) The Successful Efforts Method 6(i ) Basic Rules 6

(i i ) Exploratory versusDevelopment WellDefini tion 7

(i i i ) Treatment of Costs ofExploratory Wells WhoseOutcome Is Undetermined 8

(iv) Successful EffortsImpairment Test 9

(v) Conveyances 9(b) The Full Cost Method 9

(i ) Basic Rules 9(i i ) Exclusion of Costs from

Amortization 10

(i i i ) The Full Cost Cei l ingTest 10

(iv) Conveyances 11

24.5 ACCOUNTING FOR NATURAL GASIMBALANCES 11

(a) Sales Method 12(b) Enti tlements Method 12(c) Gas Balancing Example 12

24.6 HARD-ROCK MINING 13

(a) Mining Operations 13(b) Sources of General ly Accepted

Accounting Principles 14

24.7 ACCOUNTING FOR MININGCOSTS 15

(a) Exploration and DevelopmentCosts 15

(b) Production Costs 16(c) Inventory 17

(i ) Metals and Minerals 17(i i ) Materials and Suppl ies 18

(d) Commodities, FuturesTransactions 18

(e) Environmental Concerns 19(f ) Shut-Down of Mines 20(g) Accounting for the Impairment

of Long-Lived Assets 20

24 • 2 OIL, GAS, AND OTHER NATURAL RESOURCES

24.1 INTRODUCTION

Accounting for oil and gas activi ties can be extremely complex because it encompasses awide variety of business strategies and vehicles. The industry’s diversity developed in re-sponse to the risk involved in the exploration process, the volati l i ty of prices, and the fluctu-ations in supply and demand for oil and gas. In addition to having a working knowledge ofaccounting procedures, the oil and gas accountant should be famil iar with the operating char-acteristics of companies involved in oil and gas activi ties and understand the impact of indi-vidual t ransactions.

Oil and gas activi ties cover a wide spectrum—ranging from exploration and production activ-i ties to the refining, transportation, and marketing of products to consumers. Special accountingrules exist for exploration and production activi ties. Accounting for refining activi ties is similarin many ways to other process manufacturing businesses. Likewise, transportation and market-ing do not dif fer signif icantly f rom one end product to another. This chapter focuses on the spe-cial accounting rules for petroleum exploration and production.

The same may be said for the mining and processing of minerals except that the accountingrules for mineral exploration and production are not so formal ized as for petroleum.

24.2 OIL AND GAS EXPLORATION ANDPRODUCING OPERATIONS

Oil- and gas-producing activi ties begin with the search for prospects—parcels of acreage thatmanagement thinks may contain economical ly viable oil or gas formations. For the most likelyprospects, the enterprise may contract with a geological and geophysical (G&G) company to testand assess the subsurface formations and their depths. Three-dimensional (3-D) seismic studiessend sound waves thousands of feet below the earth’s surface, record the mil l ion echoes from un-derground strata, and use powerful computers to read the echoes to create 3-D electronic imagesof the underground formations. With these ultrasounds of Mother Earth, the enterprise evaluatesthe various prospects, rejecting some and accepting others as suitable for acquisition of leaserights (prospecting may be done before or af ter obtaining lease rights).

Special ists cal led landmen may be used to obtain lease rights. A landman is in effect a leasebroker who searches ti tles and negotiates with property owners. Although the landman may bepart of the company’s staf f, oil and gas companies of ten acquire lease rights to propertiesthrough independent landmen. Consideration for leasing the mineral r ights usual ly includes abonus (an immediate cash payment to the lessor) and a royalty interest retained by the lessor (aspecif ied percentage of subsequent production minus appl icable production taxes).

Once the leases have been obtained and the rights and obl igations of al l parties have beendetermined, exploratory dri l l ing begins. Because dri l l ing costs run to hundreds of thousands ormil l ions of dol lars, many companies reduce their capital commitment and related risks byseeking others to participate in joint venture arrangements. Participants in a joint venture arecal led joint interest owners; one owner, usual ly the enterprise that obtained the leases, acts as

24.8 ACCOUNTING FOR MININGREVENUES 21

(a) Sales of Minerals 21(b) Tol l ing and Royal ty Revenues 22

24.9 SUPPLEMENTARY FINANCIALSTATEMENT INFORMATION—ORE RESERVES 22

24.10 ACCOUNTING FOR INCOMETAXES 22

24.11 FINANCIAL STATEMENTDISCLOSURES 23

24.12 SOURCES AND SUGGESTEDREFERENCES 23

24.2 OIL AND GAS EXPLORATION AND PRODUCING OPERATIONS 24 • 3

operator. The operator manages the venture and reports to the other, nonoperator participants.The operator ini tial ly pays the dri l l ing costs and then bil ls those costs to the nonoperators. Insome cases, the operator may col lect these costs from nonoperators in advance.

The operator acquires the necessary suppl ies and subcontracts with a dri l l ing company fordri l l ing the well. The dri l l ing time may be a few days, several months, or even a year or longerdepending on many factors, particularly well depth and location. When the hole reaches thedesired depth, various instruments are lowered that “ log the well ” to detect the presence of oilor gas. The joint interest owners evaluate the dri l l ing and logging results to determinewhether suff icient oil or gas can be extracted to justif y the cost of completing the well. If t heevaluation is negative, the well is plugged and abandoned as a dry hole. If suff icient quanti tiesof crude oil or natural gas (hydrocarbons) appear to be present, the well is completed andequipment is instal led to extract and separate the hydrocarbons from the water coming fromthe underground reservoir. Completion costs are substantial and may even exceed the ini tialdri l l ing costs.

Before production begins (sometimes even before the well is dri l led), the enterprise selectsoil and gas purchasers and negotiates sales contracts. To transport the oil or gas from the well,a trunk line may be buil t to the nearest major pipeline; crude oil also may be stored in tanks atthe production site and removed later by truck. The production owner and purchasers prepareand sign division orders, which are revenue distribution contracts specifying each owner’sshare of revenues. If the division order specif ies that the purchaser is to pay al l revenues to theoperator, the operator must distribute the appropriate amounts to the other joint interest own-ers and the lessor(s).

The various factors that determine the success or fai lure of oil and gas exploration activi-ties include many uncertainties. These factors set the oil and gas industry apart from manyother capital-intensive industries. Some of these factors include the fol lowing:

• Anticipated Success of Drilling. Even with the recent technological advances in 3-D seis-mic, there is sti l l substantial r isk of not finding a commercial petroleum reservoir af terspending hundreds of thousands of dol lars (or more) dri l l ing a well to the target formation.Exploration success is also af fected by dri l l ing risks such as stuck dri l l pipes, blowouts,and improper completions.

• Taxation. A substantial portion of the revenues from the sale of crude oil and natural gasgoes directly or indirectly to the federal and state governments in the form of severancetaxes, ad valorem taxes, and income taxes. In the late 1970s, Congress enacted the Wind-fal l Prof i t Tax on domestic crude oil. On August 25, 1988, the Windfal l Prof i t Tax wasrepealed for al l crude oil removed af ter that date. After the various taxes, royalties to thelandowner, and production costs have been deducted, the producer’s income from the saleof crude oil and natural gas may be only a small percentage of gross revenues. Except forcertain tax credits relating to “Tight Sands” and coalbed methane gas production, mosttax-related incentives have been eliminated through tax legislation since 1986.

• Product Pr ice and Marketabilit y. U.S. crude oil production meets only hal f of the country’sdemand and is readily marketable. The United States imports crude oil f rom Venezuela,Canada, and other countries. For the past several years, U.S. prices of crude oil have fluc-tuated widely due to numerous factors including world pol i tics, economic conditions, andtechnology advances. High qual i ty crude oil sold for $42 per barrel in late 1979, $12 brief lyin 1986, $40 brief ly in 1990, in the $20 range in 1991, $18 at the end of 1995, $24 at theend of 1996, $15.50 at the end of 1997, and under $14 by spring of 1997. Oil prices alsovary due to the qual i ty of the oil and the location of the oil f ield. In a given month, heavysour crude oil in Cal ifornia may sell for hal f or two-thirds the price of l ight, sweet crude oilproduced in Oklahoma.

In the 1990’s natural gas price volati l i ty has exceeded that of crude oil. U.S. natural gasproduction meets substantial ly al l of the country’s needs, af ter competi tion from gas


imported from Canada. Demand for natural gas is seasonal in the United States—high inthe winter months for space heating and low in the summer for most areas of the country.Signif icant quanti ties of gas produced in the summer is transported by pipelines to under-ground formations for temporary storage unti l the winter season. Such temporary storagehelps to reduce the seasonal price fluctuations.

Because of the volati l i ty in oil and gas prices, a number of price hedging mechanismshave been developed, including futures contracts, long-term hedging arrangements, andproduct swaps.

• Timing of Production. How quickly oil and gas are produced directly af fects the paybackperiod of an investment and its financial success or fai lure. The timing of productionvaries with the geologic characteristics of the reservoir and the marketabil i ty of the prod-uct. Reservoirs may contain the same gross producible reserves, yet the timing of produc-tion causes signif icant dif ferences in the present value of the future revenue stream.

• Acreage and Drilling Costs.Many U.S. companies are focusing on exploration outsidethe United States. The United States is a mature exploration area producing 10% of theworld’s oil production from 63% of the world’s oil wells. The global availabil i ty ofqual i ty exploration acreage, dri l l ing personnel, and suppl ies has increased, whereas therelated costs have dropped signif icantly since the boom period of the late 1970s andearly 1980s.

24.3 ACCOUNTING FOR JOINT OPERATIONS

Oil- and gas-producing activi ties are recorded in the same general manner as most other activ-i ties that use manual or automated revenue, accounts payable, and general ledger systems.There are signif icant dif ferences in the data gathering and reporting requirements, however,depending on whether the enti ty is an operator or a nonoperator for a given joint venture. Thetwo major accounting systems unique to oil- and gas-producing activi ties are the joint interestbil l ing system and the revenue distribution system. The operator’s joint interest bil l ing systemmust properly calculate and record the operator’s net cost as well as the costs to be bil led tothe nonoperators. Likewise, the revenue distribution system should properly al locate cash re-ceipts among venture participants; this entails fi rst recording the amounts payable to the par-ticipants and later making the appropriate payments.

As discussed previously, joint interest operations evolved because of the need to share thef inancial burden and risks of oil- and gas-producing activi ties. Joint operations typical ly takethe form of a simple joint venture evidenced by two formal agreements, general ly referred to asan exploration agreement and an operating agreement. These agreements define the geographicarea involved, designate which party wil l act as operator of the venture, define how revenueand expenses wil l be divided, and set forth the rights and responsibil i ties of al l parties to theagreement. The operating agreement also establ ishes how the operator is to bil l the nonopera-tors for joint venture expenditures and provides nonoperators with the right to conduct “ jointinterest audits” of the operator’s accounting records.

Accounting for joint operations is basical ly the same as accounting for operations when a property is completely owned by one party, except that in joint operations, revenues andexpenses are divided among al l of the joint venture partners. The fol lowing section discussesaccounting for joint operations, fi rst from the operator’s standpoint and then from the non-operators’ perspective.

(a) OPERATOR ACCOUNTING. The operator typical ly records revenue and expenses for awell on a 100%, or “gross,” basis and then al locates the revenue and expenses to the nonopera-tors based on ownership percentages maintained in the division order and joint interest master

24.3 ACCOUNTING FOR JOINT OPERATIONS 24 • 5

f i les. One approach is to record the full invoice or remittance advice amount and use contra orclearing accounts that set up the amounts due from or to the nonoperators. Recording transac-tions by means of contra accounts facil i tates generation of information that management usesto review operations on a gross basis.

Before dri l l ing and completing a well, the operator prepares an authorization for expendi-ture (AFE) itemizing the estimated costs to dri l l and complete the well. A lthough AFEs arenormally required by the operating agreement, they are so useful as a capital budgeting toolthat they are routinely used for al l major expenditures by oil and gas companies, even if nojoint venture exists. In addition to AFEs, the operator’s f ield supervisor or engineer at thewell site prepares a daily dri l l ing report, which is an abbreviated report of the current statusand the dri l l ing or completion activi ty of the past 24 hours. That report may be compared witha dri l l ing report prepared by the dri l l ing company (also cal led a “tour” report). Some dailydri l l ing reports indicate estimated cumulative costs incurred to date.

For shal low wells that are quickly and easily dri l led, the AFE subsidiary ledger, combinedwith the daily dri l l ing report, may provide the basis for the operator’s estimate of costs in-curred but not invoiced. For other wells, however, the engineering department prepares an esti-mate of cumulative costs incurred through year-end as a basis for recording the accrual and, ifmaterial, the commitments for future expenditures.

The operator normally f urnishes the nonoperators with a monthly summary bil l ing thatshows the amount owed the operator on a property-by-property basis. The summary bil l ing isaccompanied by a separate joint operating statement for each property. The joint operatingstatement contains a description of each expenditure and shows the total expenditures for theproperty. The statement also shows the al location of expenditures among the joint interest par-ticipants. The operator usual ly does not furnish copies of third-party invoices supporting itemsappearing on the joint interest bil l ing, but the third-party invoices can be examined and copiedduring the nonoperators’ audit of the joint account. The operator may also furnish the nonoper-ators a production report and at a later date remit checks to the nonoperators for their share ofproduction.

(b) NONOPERATOR ACCOUNTING. From the nonoperators’ standpoint, the accountingfor joint operations is basical ly the same as that fol lowed by the operator. It is not unusual for acompany to act as an operator on some properties and a nonoperator on others. To be able tomake comparisons and evaluations that include both types of properties, nonoperators shouldalso record items on a gross basis. A nonoperator should develop a control procedure for re-viewing the joint operating statement to determine whether the operator is complying with thejoint operating agreement, is bil l ing the nonoperator only val id charges at the appropriate per-centages, and is distributing the appropriate share of revenue.

(c) OTHER ACCOUNTING PROCEDURES. The operating agreement may permit the op-erator to charge the joint venture a monthly f ixed fee to cover its internal costs incurred inoperating the joint venture. Alternatively, the agreement may provide for reimbursement of theoperator’s actual costs.

The parties in a joint operation may agree either to share costs in a proportion that is dif-ferent from that used for sharing revenue or to change the sharing percentages af ter a specif icevent takes place. Typical ly, that event is “payout,” the point at which certain venturers haverecovered their ini tial investment or an agreed-upon multiple of the investment. Al l parties in-volved in joint operations encounter payout situations at some time. Controls must be designedto monitor payout status to ensure that al l parties are satisf ied that revenues and costs havebeen properly al located in accordance with the joint operating agreement.

(d) OVERVIEW OF ACCOUNTING STANDARDS. The fol lowing pronouncements setforth general ly accepted accounting principles unique to oil and gas producing activi ties:


• Statement of Financial Accounting Standards (SFAS) No. 19, which describes a “success-ful efforts” method of accounting,

• SFAS No. 25, which recognizes that other methods may be appropriate,

• SEC Regulation S-X, Article 4, Section 10 (also referred to as S-X Rule 4-10), which pre-scribes two acceptable methods for publ ic enti ties—either the successful efforts methoddescribed in SFAS No. 19 or a “full cost ” method, as described in S-X Rule 4-10, and

• SFAS No. 69, which requires supplementary disclosures of oil- and gas-producingactivi ties.

Additional guidance and interpretations are found in Financial Accounting Standards Board(FASB) Interpretations, Securi ties Exchange Commission (SEC) Staf f Accounting Bulletins,surveys in industry accounting practices, and petroleum accounting journals and petroleum ac-counting textbooks.

The primary dif ferences between the successful efforts and full cost methods center aroundcosts to be capital ized and those to be expensed. As the name impl ies, under the successful ef-forts method, only those costs that lead to the successful discovery of reserves are capital ized,while the costs of unsuccessful exploratory activi ties are charged directly to expense. Underthe full cost method, al l exploration efforts are treated as capital costs under the theory thatthe reserves found are the result of al l costs incurred. Both methods are widely used; however,larger companies tend to fol low the successful efforts method.

Under income tax law and regulations, al l exploration and development costs, except lease-hold and equipment costs, are general ly expensed as incurred. Petroleum producing companieswith signif icant refining or marketing activi ties (cal led “ Integrateds” as opposed to “Indepen-dents”) must capital ize 30% of intangible well costs to be amortized over sixty months. Lease-hold costs are expensed by complex depletion deductions which, for independents, can exceedactual costs. Equipment costs are depreciated using accelerated methods. Many independentU.S. oil and gas-producing companies pay the alternative minimum tax.

24.4 ACCEPTABLE ACCOUNTING METHODS

(a) The Successful Efforts Method

(i) Basic Rules. The fol lowing points summarize the major aspects of the successful ef for tsmethod of accounting for oil and gas property costs:

• The costs of al l G&G studies to find reserves are charged to expense as incurred.

• Lease acquisition costs for unproved properties are ini tial ly capital ized. Unproved prop-erties are those on which no economical ly recoverable oil or gas has been demonstrated toexist. Unproved properties are to be assessed for impairment at least annual ly.

• If an unproved property becomes impaired because of such events as pending lease ex-piration or an unsuccessful exploratory well (dry hole), the loss is recognized and a val-uation al lowance is establ ished to reflect the property’s impairment. Two approaches toimpairment are used: (1) Property-by-property (typical ly used by small companies orsituations involving signif icant acreage costs), or (2) A formula approach based on factorssuch as historical success ratios and average lease terms (typical ly used by larger com-panies with a signif icant number of smaller properties).

• Once proved reserves are found on a property, the property is considered proved and theacquisition costs are amortized on a unit-of-production basis over the property’s produc-ing li fe based on total proved reserves (both developed and undeveloped reserves). TheSFAS No. 25 defini tion of proved reserves may be summarized as the estimated volumes

24.4 ACCEPTABLE ACCOUNTING METHODS 24 • 7

of oil and gas that geological and engineering data demonstrate with reasonable certaintyto be recoverable in future years from known reservoirs under existing economic and op-erating conditions.

• If both oil and gas are produced from the property, the unit is normally equivalent barrelsor mcfs, whereby gas is converted to equivalent barrels (or barrels are converted to equiv-alent mcfs) based on relative energy content. A common conversion factor is 5.6 mcfs to 1equivalent barrel.

• For a property containing both oil and gas, the unit may reflect ei ther oil or gas if:

—The relative property of oil and gas extracted in the current period is expected to con-tinue in the future, or

—The reflected mineral clearly dominates the other for both current production andreserves.

• Carrying costs required to retain rights to unproved properties (delay rentals, ad valoremtaxes, etc.) are charged to expense.

• Exploratory wells are capital ized ini tial ly as wells-in-progress and expensed if proved re-serves are not found. Successful exploratory wells are capital ized, as are their completioncosts (setting casing and other costs necessary to begin producing the well ).

• Costs of dri l l ing development wells (even the rare dry ones) are capital ized.

• Costs of successful exploratory wells, along with the costs of dri l l ing development wellson the lease, are amortized on a unit-of-production basis over the property’s proved de-veloped reserves on:

—A property-by-property basis, or

—The basis of some reasonable aggregation of properties with a common geologic orstructural feature or stratigraphic condition, such as a reservoir or field

• Once production has begun, al l regular production costs are charged to expense.

• Capital ized interest, under the requirements of SFAS 34, would also be capital ized aspart of the cost of unevaluated properties during the evaluation phase.

(ii) Exploratory versus Development Well Definition. Because Reg. S-X requires that thecosts of dry exploratory wells be charged to expense, whereas the costs of dry developmentwells are capital ized, it is important to properly classify wells. Regulation S-X, Rule 4-10, de-f ines the two categories of wells as fol lows:

1. Development Well. A well dri l led within the proved area of an oil or gas reservoir to thedepth of a stratigraphic horizon known to be productive.

2. Exploratory Well. A well dri l led to find and produce oil or gas in an unproved area, tof ind a new reservoir in a field previously found to be productive of oil or gas in anotherreservoir, or to extend a known reservoir. General ly, an exploratory well is any well thatis not a development well, a service well, or a stratigraphic test well.

These defini tions may not coincide with those that have been commonly used in the indus-try (typical ly, the industry defini tion of a development well is more liberal than Reg. S-X,Rule 4-10). This results in two problems:

• Improper classif ication of certain exploratory dry holes as development wells (the prob-lem occurs primarily wi th stepout or delineation wells dri l led at the edge of a producingreservoir), and

• Inconsistencies between the dri l l ing statistics found in the forepart of Form 10-K (usu-al ly prepared by operational personnel) and the supplementary f inancial statement infor-mation required by SFAS No. 69 (usual ly prepared by accounting personnel).


(iii) Treatment of Costs of Exploratory Wells Whose Outcome Is Undetermined. As setout below, SFAS No. 19 effectively curtails extended deferral of the costs of an exploratorywell whose outcome has not yet been determined:

Accounting When Drilling of an Exploration Well Is Completed

Par. 31: . . . the costs of dri l l ing an exploratory well are capital ized as part of the enter-prise’s uncompleted wells, equipment, and faci l i ties pending determination of whether thewell has found proved reserves. That determination is usual ly made on or shortly af ter com-pletion of dri l l ing the well, and the capital ized costs shal l ei ther be charged to expense or bereclassif ied as part of the costs of the enterprise’s wells and related equipment and faci l i tiesat that time. Occasional ly, however, an exploratory well may be determined to have found oiland gas reserves, but classif ication of those reserves as proved cannot be made when dri l l ingis completed. In those cases, one or the other of the fol lowing subparagraphs shal l apply de-pending on whether the well is dri l led in an area requiring a major capital expenditure, suchas a trunk pipeline, before production from that well could begin:

a. Exploratory wells that f ind oil and gas reserves in an area requiring a major capital ex-penditure, such as a trunk pipeline, before production could begin. On completion ofdri l l ing, an exploratory well may be determined to have found oil and gas reserves, butclassif ication of those reserves as proved depends on whether a major capital expenditurecan be justi f ied which, in turn, depends on whether additional exploratory wells find asuff icient quanti ty of additional reserves. That situation arises principal ly wi th ex-ploratory wells dri l led in a remote area for which production would require constructinga trunk pipeline. In that case, the cost of dri l l ing the exploratory well shal l continue to becarried as an asset pending determination of whether proved reserves have been foundonly as long as both of the fol lowing conditions are met:

(1) The well has found a suff icient quanti ty of reserves to justi f y its completion as a pro-ducing well i f the required capital expenditure is made.

(2) Dril l ing of the additional exploratory wells is under way or fi rmly planned for thenear future.

Thus, if dri l l ing in the area is not under way or fi rmly planned, or if the well has notfound a commercial ly producible quanti ty of reserves, the exploratory well shal l beassumed to be impaired, and its costs shal l be charged to expense.

b. All other exploratory wells that f ind oil and gas reserves. In the absence of a determina-tion as to whether the reserves that have been found can be classif ied as proved, the costsof dri l l ing such an exploratory well shal l not be carried as an asset for more than one yearfol lowing completion of dri l l ing. If, af ter that year has passed, a determination thatproved reserves have been found cannot be made, the well shal l be assumed to be im-paired, and its costs shal l be charged to expense.

Par 32: Paragraph 32 is intended to prohibi t, in al l cases, the deferral of the costs of ex-ploratory wells that f ind some oil and gas reserves merely on the chance that some event to-tal ly beyond the control of the enterprise wil l occur, for example, on the chance that thesell ing prices of oil and gas wil l increase suff iciently to result in classif ication of reserves asproved that are not commercial ly recoverable at current prices.

Accounting When Drilling of an Exploratory-Type Stratigraphic Test Well Is Completed

Par 33: As specif ied in paragraph .110, the costs of dri l l ing an exploratory-type stratigraphictest well are capital ized as part of the enterprise’s uncompleted wells, equipment, and faci l-i ties pending determination of whether the well has found proved reserves. When that deter-mination is made, the capital ized costs shal l be charged to expense if proved reserves are notfound or shal l be reclassif ied as part of the costs of the enterprise’s wells and related equip-ment and faci l i ties if proved reserves are found.

Par 34: Exploratory-type stratigraphic test wells are normal ly dri l led on unproved of fshoreproperties. Frequently, on completion of dri l l ing, such a well may be determined to havefound oil and gas reserves, but classif ication of those reserves as proved depends on whethera major capital expenditure—usual ly a production platform—can be justi f ied which, in turn,

24.4 ACCEPTABLE ACCOUNTING METHODS 24 • 9

depends on whether additional exploratory-type stratigraphic test wells find a suff icientquanti ty of additional reserves. In that case, the cost of dri l l ing the exploratory-type strati-graphic test well shal l continue to be carried as an asset pending determination of whetherproved reserves have been found only as long as both of the fol lowing conditions are met:

1. The well has found a quanti ty of reserves that would justi f y its completion for productionhad it not been simply a stratigraphic test well.

2. Dril l ing of the additional exploratory-type stratigraphic test wells is under way or fi rmlyplanned for the near future.

Thus, if associated stratigraphic test dri l l ing is not under way or fi rmly planned, or if the wellhas not found a commercial ly producible quanti ty of reserves, the exploratory-type strati-graphic test well shal l be assumed to be impaired, and its costs shal l be charged to expense.

(iv) Successful Efforts Impairment Test. SFAS No. 121 on impairment of long-lived assetsamends SFAS No. 19 and requires appl ication of SFAS No. 121 impairment rules to capital izedcosts of proved oil and gas properties for companies fol lowing the successful efforts method ofaccounting.

(v) Conveyances. SFAS No. 19 and Reg. S-X, Rule 4-10(m) provides rules to account formineral property conveyances and related transactions. Conveyances of “ production pay-ments” repayable in fixed monetary terms, that is, loans in substance, are accounted for asloans. Conveyances of production payments repayable in fixed production volumes from speci-f ied production are deemed to be property sales whereby proved reserves are reduced but theproceeds from sale of a production payment are credited to deferred revenue to be recognizedas revenue as the seller delivers future petroleum volumes to the holder of the production pay-ment. Gain or loss is not recognized for conveyances of (1) a pool ing of assets in a joint ventureto find, develop, or produce oil and gas or (2) such assets in exchange for other assets used inoil- and gas-producing activi ties. Gain is not recognized (but loss is) for conveyance of a par-tial property interest when substantial uncertainty exists as to the recovery of costs for the re-tained interest portion or when the seller has substantial obl igation for future performancesuch as dri l l ing a well. For other conveyances, gain or loss is recognized unless prohibi tedunder accounting principles appl icable to enterprises in general.

(b) THE FULL COST METHOD

(i) Basic Rules. Under Reg. S-X, Rule 4-10, oil and gas property costs are accounted foras fol lows:

• Al l costs associated with property acquisition, exploration and development activi tiesshal l be capital ized by country-wide cost center. Any internal costs that are capital izedshal l be limited to those costs that can be directly identif ied with the acquisition, explo-ration and development activi ties undertaken by the reporting enti ty for its own account,and shal l not include any costs related to production, general corporate overhead or similaractivi ties.

• Capital ized costs within a cost center shal l be amortized on the unit-of-production basisusing proved oil and gas reserves, as fol lows:

— Costs to be amortized shal l include (A) al l capital ized costs, less accumulated amorti-zation, excluding the cost of certain unevaluated properties not being amortized;(B) the estimated future expenditures (based on current costs) to be incurred in devel-oping proved reserves; and (C) estimated dismantlement and abandonment costs, net ofestimated salvage values. [The current rule is referring to undiscounted future de-commissioning, restoration and abandonment costs, net of estimated salvage values(“ net abandonment costs”). In early 1996, the FASB issued an exposure draf t for aproposed SFAS on accounting for certain liabil i ties related to closure or removal oflong-lived assets. If adopted as draf ted, the new SFAS would amortize capital ized


costs that include a charge corresponding to the accrued liabil i ty for net abandon-ment costs. The liabil i ty reflects a present value discounted at a safe rate of inter-est.]

— Amortization shal l be computed on the basis of physical uni ts, with oil and gas con-verted to a common unit of measure on the basis of their approximate relative energycontent, unless economic circumstances (related to the effects of regulated prices) indi-cated that use of revenue is a more appropriate basis of computing amortization. In thelatter case, amortization shal l be computed on the basis of current gross revenues fromproduction in relation to future gross revenues (excluding royalty payments and netprof i ts disbursements) based on current prices from estimated future production ofproved oil and gas reserves (including consideration of changes in existing prices pro-vided for only by contractual arrangements). The effect on estimated future grossrevenues of a signif icant price increase during the year shal l be reflected in the amorti-zation provision only for the period af ter the price increase occurs.

In some cases it may be more appropriate to depreciate natural gas cycling and process-ing plants by a method other than the unit-of-production method.

Amortization computations shal l be made on a consol idated basis, including investeesaccounted for on a proportionate consol idation basis. Investees accounted for on the eq-uity method shal l be treated separately.

(ii) Exclusion of Costs From Amortization. SEC Financial Report Reg. S-X, Rule 4–10,al lows two alternatives:

1. Immediate inclusion of al l costs incurred in the amortization base.

2. Temporary exclusion of al l acquisition and exploration costs incurred that directly re-late to unevaluated properties and certain costs of major development projects.

Unevaluated properties are defined as those for which no determination has been made ofthe existence or nonexistence of proved reserves. Costs that may be excluded are al l those costsdirectly related to the unevaluated properties (i.e., leasehold acquisitions costs, delay rentals,G&G, exploratory dri l l ing, and capital ized interest). The cost of exploratory dry holes shouldbe included in the amortization base as soon as the well is deemed dry.

These excluded costs must be assessed for impairment annual ly, ei ther:

• individual ly for each signif icant property (i.e., capital ized cost exceeds 10% of the netfull cost pool ), or

• in the aggregate for insignif icant properties (i.e., by transferring the excluded propertycosts into the amortization base ratably on the basis of such factors as the primary leaseterms of the properties, the average holding period, and the relative proportion of proper-ties on which proved reserves have been found previously).

(iii) The Full Cost Ceiling Test. SFAS No. 121 impairment rules are effectively supersededby the fol lowing full cost “ceil ing test ” specif ied in Reg. S-X, Rule 4–10(e)(4):

• For each cost center capital ized costs, less accumulated amortization and related deferredincome taxes, shal l not exceed an amount (the cost center cei l ing) equal to the sum of: (A) The present value of estimated future net revenues computed by applying currentprices of oil and gas reserves (with consideration of price changes only to the extent pro-vided by contractual arrangements) to estimated future production of proved oil and gasreserves as of the date of the latest balance sheet presented, less estimated future expen-di tures (based on current costs) to be incurred in developing and producing the proved re-serves computed using a discount factor of ten percent and assuming continuation ofexisting economic conditions; plus (B) the cost of properties not being amortized pur-suant to paragraph (c)(3)(i i ) of this section; plus (C) the lower of cost or estimated fair

24.5 ACCOUNTING FOR NATURAL GAS IMBALANCES 24 • 11

value of unproven properties included in the costs being amortized; less (D) income taxeffects related to dif ferences between the book and tax basis of the properties referred toin paragraphs (c)(4)(i ) (B) and (C) of this section.

• If unamortized costs capital ized within a cost center, less related deferred income taxes, exceed the cost center cei l ing, the excess shal l be charged to expense and sepa-rately disclosed during the period in which the excess occurs. Amounts thus required to be wri tten of f shal l not be reinstated for any subsequent increase in the cost centerceil ing.

Part D, income tax effects, is poorly worded and refers to the income tax effects related to theceil ing components in parts A, B, and C al lowing for consideration of the oil and gas properties’tax bases and related depletion carryforwards and related net operating loss carryforwards.

Two other unique aspects of the full cost ceil ing test are:

• Ceiling Test Exemption for Purchases of Proved Proper ties. A petroleum producing com-pany might purchase proved properties for more than the present value of estimated fu-ture net revenues, causing net capital ized costs to exceed the cost center ceil ing on thedate of purchase. To avoid the wri tedown, the company may request from the SEC staf f atemporary (usual ly one year) waiver of applying the ceil ing test. The company must beprepared to demonstrate that the purchased properties’ additional value exists beyondreasonable doubt. For more details see SAB No. 47, Topic 12, D-3a.

• Effect of Subsequent Event. If, af ter year-end but prior to the audit report date, ei ther(1) additional reserves are proved up on properties owned at year-end, or (2) price in-creases become known, then such subsequent events may be considered in the year-endceil ing test to mitigate a wri tedown of capital ized costs.

The avoidance of a wri tedown must be adequately disclosed, but the subsequent eventsshould not be considered in the required disclosures of the company’s proved reserves andstandardized measure of discounted future net cash flows relating to such reserves (asfurther described in this Chapter’s section on Financial Statement Disclosures). For moredetails, see SAB No. 47, Topic 12, D-3b.

(iv) Conveyances. Reg. S-X, Rule 4-10(c)(6) provides that accounting for conveyances wil lbe the same as for successful efforts accounting except that sales of oil and gas properties areto be accounted for as adjustments of capital ized costs with no recognition of gain or loss (“un-less such adjustments would signif icantly al ter the relationship between capital ized costs andproved reserves”). Exceptions are also made in some circumstances for property sales to part-nerships and joint ventures in that (1) proceeds that are reimbursements of identif iable, currenttransaction expenses may be credited to income and (2) a petroleum company may recognize inincome “management fees” from certain types of managed limited partnerships. When a com-pany acquires an oil and gas property interest in exchange for services (such as dri l l ing wells),income may be recognized in limited circumstances.

24.5 ACCOUNTING FOR NATURAL GAS IMBALANCES

Accounting techniques are basical ly the same whether revenue is generated by sell ing crudeoil or natural gas. However, joint venture participants usual ly sell their crude oil col lectivelybut may individual ly market and sell their shares of natural gas production. When a jointventure owner physical ly takes and sells more or less gas than its enti tled share, a “gas im-balance” is created that is later reversed by an equal, but opposite, imbalance or by settle-ment in cash.

For example, if two joint venture participants each own 50% working interests in a well, andone company decides to sell gas on the spot market but the other company declines to sell due to


a low spot price (or other factors), the company sell ing gas wil l receive 100% of revenue af terpaying the royalty interests. The sell ing company is in an overproduced capacity with respect tothe well (the company is enti tled to 50% of the gas af ter royalties but had received 100%). A gasimbalance can also occur between a gas producer and the gas transmission company that re-ceives the producer’s gas but delivers a dif ferent volume to the producer’s customer.

Gas-producing companies account for gas imbalances under ei ther the Sales method or theEnti tlements method.

(a) SALES METHOD. Under the sales method, the company recognizes revenue and a re-ceivable for the volume of gas sold, regardless of ownership of the property. For example, ifCompany A owns a 50% net revenue interest in a gas property but sells 100% of the productionin a given month, the company would recognize 100% of the revenue generated. In a subse-quent month, if Company A sells no gas (and the other owners “make up” the imbalance),Company A would recognize zero revenue. Company A would reduce its estimate of proved re-serves for any future production that it must give up to meet a gas imbalance obl igation andincrease proved reserves for any additional f uture production it has a right to receive fromother joint venture participants to eliminate an existing gas imbalance.

Although this method is rather simple from a revenue accounting standpoint, it presentsother problems. Regardless of the revenue method chosen, the operator wil l issue joint interestbil l ing statements for expenses based on the ownership of the property. Depending on the gas-balancing situation, the sales method may present a problem with the matching of revenues andexpenses in a period. If a signif icant imbalance exists at the end of an accounting period, theaccountant may be required to analyze the situation and record additional expenses (or reduceexpenses depending on whether the property is overproduced or underproduced).

(b) ENTITLEMENTS METHOD. Under the enti tlements method, the company recognizesrevenue based on the volume of sales to which it is enti tled by its ownership interest. For ex-ample, if Company A owns a 50% net revenue interest but sells 100% of the production in agiven month, the company would recognize 50% of the revenue generated. Company A wouldrecognize a receivable for 100% of the revenue with the dif ference being recorded in a payable(or deferred revenue) account. When the imbalance is corrected, the payable account wil l be-come zero, thus indicating that the property is “ in balance.”

This method correctly matches revenues and expenses but presents another accountingissue. If a property is signif icantly imbalanced, Company A may f ind itself in a position thatreserves are insuff icient to bring the well back to a balanced condition. If Company A is un-derproduced in this situation, a receivable (or deferred charge) may be recorded in the assetcategory that has a questionable real ization. In addition, the company is real ly under- or over-produced in terms of volumes (measured in cubic feet) of gas. A value per cubic foot is as-signed based on the sale price at the period of imbalance. If the price is signif icantly dif ferentwhen the correction occurs, the receivable may not show a zero balance in the accountingrecords.

(c) GAS BALANCING EXAMPLE

Facts: Company A owns a 50% net revenue.

Gas sales for January are 5,000 mcf @ $2.00 per MCF.

Gas sales for February are 5,000 mcf @ $2.00 per MCF.

In January, Company A sells 100% of gas production to its purchaser.

In February, Company sells zero gas to its purchaser.

24.6 HARD-ROCK MINING 24 • 13

JANUARY ACCOUNTING ENTRIES

Under the Sales Method Debit Credit

Accounts receivable, gas sales $10,000Gas revenue $10,000

Under the Entit lements Method

Accounts receivable, gas sales $10,000Gas revenue $05,000Payable $05,000

FEBRUARY ACCOUNTING ENTRIES

Under the Sales Method No entries are recorded

Under the Entit lements Method

Payable $05,000Gas revenue $05,000

24.6 HARD-ROCK MINING

(a) MINING OPERATIONS. The principal dif ference between hard-rock mining companiesand companies involved in oil- and gas-producing activi ties, previously discussed in this chap-ter, relates to the nature, timing, and extent of expenditures incurred for exploration, develop-ment, production, and processing of minerals.

General ly in the mining industry, a period of as long as several years elapses between thetime exploration costs are incurred to discover a commercial ly viable body of ore and the expen-diture of development costs, which are usual ly substantial, to complete the project. Therefore,the economic benefi ts derived from a project are long-term and subject to the uncertainties in-herent in the passage of t ime. In contrast, the costs related to exploring for deposits of oil and gasare expended general ly over a relatively short time. Major exceptions would be of fshore and for-eign petroleum exploration and development.

Li ke petroleum exploration and production, the mining industry is capital intensive. Sub-stantial investments in property, plant, and equipment are required; usual ly they representmore than 50% of a mining company’s total assets. The signif icant capital investments of min-ing companies and the related risks inherent in any long-term major project may af fect the re-coverabil i ty of capital ized costs.

The operational stages in mining companies vary somewhat depending on the type of min-eral, because of dif ferences in geological, chemical, and economic factors. The basic opera-tions common to mining companies are exploration, development, mining, mil l ing, smelting,and refining.

Exploration is the search for natural accumulations of minerals with economic value. Ex-ploration for minerals is a special ized activi ty involving the use of complex geophysical andgeochemical equipment and procedures. There is an element of f inancial r isk in every decisionto pursue exploration, and explorers general ly seek to minimize the costs and increase theprobabil i ty of success. As a result, before any f ieldwork begins, extensive studies are madeconcerning which types of minerals are to be sought and where they are most likely to occur.Market studies and forecasts, studies of geological maps and reports, and logistical evalua-tions are performed to provide information for use in determining the economic feasibil i ty of apotential project.

Exploration can be divided into two phases, prospecting and geophysical analysis. Prospect-ing is the search for geological information over a broad area. It embraces such activi ties as


geological mapping, analysis of rock types and structures, searches for direct manifestationsof mineral ization, taking samples of minerals found, and aeromagnetic surveys. Geophysicalanalysis is conducted in specif ic areas of interest local ized during the prospecting phase. Rockand soil samples are examined, and the earth’s crust is monitored directly for magnetic, gravi-tational, sonic, radioactive, and electrical data. Based on the analysis, targets for trenching,test pits, and exploratory dri l l ing are identif ied. Dri l l ing is particularly useful in evaluatingthe shape and character of a deposit. Analysis of samples is necessary to determine the gradeof the deposit.

Once the grade and quanti ty of the deposit have been estimated, the mining company mustdecide whether developing the deposit is technical ly feasible and commercial ly viable. Thevalue of a mineral deposit is determined by the intrinsic value of the minerals present and bythe nature and location of their occurrence. In addition to the grade and qual i ty of the ore,such factors as the physical accessibil i ty of the deposit, the estimated costs of production, andthe value of joint products and by-products are key elements in the decision to develop a de-posit for commercial exploi tation.

The development stage of production involves planning and preparing for commercial oper-ation. Development of surface mines is relatively straightforward. For open-pit mines, whichare surface mines, the principal procedure is to remove suff icient overburden to expose theore. For strip mines, an ini tial cut is made to expose the mineral to be mined. For undergroundmines, data resulting from exploratory dri l l ing is evaluated as a basis for planning the shaf tsand tunnels that wil l provide access to the mineral deposit.

Substantial capital investment in mineral r ights, machinery and equipment, and related fa-cil i ties general ly is required in the development stage.

Mining breaks up the rock and ore to the extent necessary for loading and removal to theprocessing location. A variety of mining techniques exists to accompl ish this. The dri l l ing andblasting technique is uti l ized frequently; an alternative is the continuous mining method, inwhich a boring or tearing machine is mounted on a forward crawler to break the material awayfrom the rock face.

Af ter removal f rom the mine site, the ore is ready for milling. The first phase of the mil l ingstage involves crushing and grinding the chunks of ore to reduce them to particle size. The sec-ond mil l ing procedure is concentration, which involves the separation of the mineral con-sti tuents from the rock.

Smelting is the process of separating the metal f rom impuri ties with which it may be chem-ical ly bound or physical ly mixed too closely to be removed by concentration. Most smelting isaccompl ished through fusion, which is the liquefaction of a metal under heat. In some cases,chemical processes are used instead of, or in combination with, heating techniques.

Refining is the last step in isolating the metal. The primary methods uti l ized are fi re refin-ing and electroly tic refining. Fire refining is similar to smelting. The metal is kept in a moltenstate and treated with pine logs, hydrocarbon gas, or other substances to enable impuri ties tobe removed. Fire refining general ly does not al low the recovery of by-products. Electroly ticrefining uses an electrical current to separate metals from a solution in such a way that by-products can be recovered.

(b) SOURCES OF GENERALLY ACCEPTED ACCOUNTING PRINCIPLES. Accountingand reporting issues in the mining industry are discussed in AICPA Accounting ResearchStudy No. 11, Financial Repor ting in the Extractive Industries (1969). In 1976, the FinancialAccounting Standards Board (FASB) issued a discussion memorandum, Financial Accountingand Reporting in the Extractive Industries, which analyzed issues relevant to the extractive in-dustries. Neither of these attempts, however, culminated in the issuance of an authori tativepronouncement for mining companies. At present, therefore, the accounting practices prevalentamong mining companies are the principal source of general ly accepted accounting practicesfor the industry.

24.7 ACCOUNTING FOR MINING COSTS 24 • 15

24.7 ACCOUNTING FOR MINING COSTS

(a) EXPLORATION AND DEVELOPMENT COSTS. Exploration and development costs aremajor expenditures of mining companies. The characterization of expenditures as either ex-ploration, development, or production usual ly determines whether such costs are capital ized orexpensed. For accounting purposes, it is useful to identif y f ive basic phases of exploration anddevelopment: prospecting, property acquisition, geophysical analysis, development before pro-duction, and development during production.

Prospecting usual ly begins with obtaining (or preparing) and studying topographical and ge-ological maps. Prospecting costs, which are general ly expensed as incurred, include (1) optionsto lease or buy property; (2) rights of access to lands for geophysical work; and (3) salaries,equipment, and suppl ies for scouts, geologists, and geophysical crews.

Proper ty acquisition includes both the purchase of property and the purchase or lease ofmineral r ights. Costs incurred to purchase land (including mineral r ights and surface rights) orto lease mineral r ights are capital ized. Acquisition costs may include lease bonus and lease ex-tension costs, lease brokers commissions, abstract and recording fees, fi l ing and patent feesand other related expenses.

Geophysical analysis is performed to discover specif ic deposits of minerals. The relatedcosts (commonly referred to as exploration costs) are accounted for in a number of dif ferentways. Most companies expense al l those costs as incurred; others capital ize them unti l suchtime as the existence or absence of an economical ly recoverable mineral reserve is establ ished.If no reserve is establ ished, the costs are wri tten of f. “ Full cost ” accounting is discussed atlength earl ier in this chapter, but has not gained general acceptance in the mining industry.

A body of ore reaches the development stage when the existence of an economical ly recov-erable mineral reserve is establ ished and the decision has been made to develop the body of orefor mining. Development costs include expenditures associated with dri l l ing, removing over-burden (waste rock), sinking shaf ts, driving tunnels, building roads and dikes, purchasing pro-cessing equipment and equipment used in developing the mine, and constructing supportingfacil i ties to house and care for the work force. In many respects, the expenditures in the devel-opment stage are similar to those incurred during exploration. As a result, it is sometimes dif-f icult to distinguish the point at which exploration ends and development begins. For example,the sinking of shaf ts and driving of tunnels may begin in the exploration stage and continueinto the development stage. In most instances, the transition from the exploration to the devel-opment stage is the same for both accounting and tax purposes.

General ly, al l costs incurred during the development stage before production starts are cap-i tal ized; usual ly they are reduced by the proceeds from the sale of any production during thedevelopment period. Development ore (ore extracted in the process of gaining access to thebody of ore) is normally incidental to the development process.

Development also takes place during the production stage. The accounting treatment of de-velopment costs incurred during the ongoing operation of a mine depends on the nature andpurpose of the expenditures. Costs associated with expansion of capacity are general ly capi-tal ized; costs incurred to maintain production are normally included in production costs in theperiod in which they are incurred. In certain instances, the benefi ts of development activi tywil l be real ized in future periods, such as when the “block caving” and open-pit mining meth-ods are used. In the block caving method, entire sections of a body of ore are intentional lycol lapsed to permit the mass removal of minerals; extraction may take place two to threeyears af ter access to the ore is gained and the block prepared. In an open-pit mine, there istypical ly an expected ratio of overburden to mineral-bearing ore over the li fe of the mine. Thecost of stripping the overburden to gain access to the ore is expensed in those periods in whichthe actual ratio of overburden to ore approximates the expected ratio. In certain instances,however, extensive stripping is performed to remove the overburden in advance of the periodin which the ore wil l be extracted. When the benefi ts of ei ther development activi ty are to be


real ized in a future accounting period, the costs associated with the development activi tyshould be deferred and amortized during the period in which the ore is extracted or the prod-uct produced.

Statement of Financial Accounting Standards (SFAS) No. 7, “Accounting and Reporting byDevelopment Stage Enterprises” (Accounting Standards Section D04), states that “an enter-prise shal l be considered to be in the development stage if i t is devoting substantial ly al l of i tsefforts to establ ishing a new business” and “the planned principal operations have not com-menced” or they “ have commenced, but there has been no signif icant revenue therefrom.” A l-though SFAS No. 7 specif ical ly excludes mining companies from its appl ication, thedefini tion of a development stage enterprise is helpful in defining the point in time at which amine’s development phase ends and its production phase begins. Mining companies usual ly useone of two points in time:

1. When both the mine and the mil l produce on a regularly scheduled basis at the plannedactivi ty levels.

2. When ore is extracted on a regular basis without regard to the mil l ing capabil i ty.

Determining when the production phase begins is important for accounting purposes be-cause, in general, at that time, certain development costs are no longer capital ized, and revenuefrom the sale of ore is included in sales revenue rather than as a reduction of capital ized devel-opment costs. The point at which production is considered to begin is sometimes stipulated inloan agreements and may ini tiate debt payments. Determining the commencement of produc-tion is also signif icant for federal income tax purposes. The point at which a mine is consideredto begin production is general ly the same for both accounting and tax purposes.

(b) PRODUCTION COSTS. When the mine begins production, production costs are ex-pensed. The capital ized property acquisition, exploration, and development costs are recog-nized as costs of production through their depreciation or depletion, general ly on theunit-of-production method over the expected productive li fe of the mine.

The principal dif ference between computing depreciation in the mining industry and inother industries is that useful lives of assets that are not readily movable from a mine site mustnot exceed the estimated li fe of the mine, which in turn is based on the remaining economical lyrecoverable ore reserves. In some instances, this may require depreciating certain miningequipment over a period that is shorter than its physical l i fe.

Depreciation charges are signif icant because of the highly capital-intensive nature of theindustry. Moreover, those charges are af fected by numerous factors, such as the physical en-vironment, revisions of recoverable ore estimates, environmental regulations, and improvedtechnology. In many instances, depreciation charges on similar equipment with dif ferent in-tended uses may begin at dif ferent times. For example, depreciation of equipment used forexploration purposes may begin when it is purchased and use has begun, while depreciationof mil l ing equipment may not begin unti l a certain level of commercial production has beenattained.

Depletion (or depletion and amortization) of property acquisition, exploration, and devel-opment costs related to a body of ore is calculated in a manner similar to the unit-of-productionmethod of depreciation. The cost of the body of ore is divided by the estimated quanti ty of orereserves or units of metal or mineral to arrive at the depletion charge per unit. The unit chargeis multipl ied by the number of units extracted to arrive at the depletion charge for the period.This computation requires a current estimate of economical ly recoverable mineral reserves atthe end of the period.

It is of ten appropriate for dif ferent depletion calculations to be made for dif ferent types ofcapital ized exploration and development expenditures. For instance, one factor to be consid-ered is whether capital ized costs relate to gaining access to the total economical ly recoverableore reserves of the mine or only to specif ic portions.


Usual ly, estimated quanti ties of economical ly recoverable mineral reserves are the basis forcomputing depletion and amortization under the unit-of-production method. The choice of thereserve unit is not a problem if there is only one product; if, however, as in many extractive op-erations, several products are recovered, a decision must be made whether to measure produc-tion on the basis of the major product or on the basis of an aggregation of al l products.General ly, the reserve base is the company’s total proved and probable ore reserve quanti ties;i t is determined by special ists, such as geologists or mining engineers. Proved and probable re-serves typical ly are used as the reserve base because of the degree of uncertainty surroundingestimates of possible reserves. The imprecise nature of reserve estimates makes it inevitablethat the reserve base wil l be revised over time as additional data becomes available. Changes inthe reserve base should be treated as changes in accounting estimates in accordance with APBOpinion No. 20, “Accounting Changes” (Accounting Standards Section A06), and accountedfor prospectively.

(c) INVENTORY. A mining company’s inventory general ly has two major components—(1) metals and minerals and (2) materials and suppl ies that are used in mining operations.

(i) Metals and Minerals. Metal and mineral inventories usual ly comprise broken ore;crushed ore; concentrate; materials in process at concentrators, smelters, and refineries;metal; and joint and by-products. The usual practice of mining companies is not to recognizemetal inventories for financial reporting purposes before the concentrate stage, that is, unti lthe majori ty of the nonmineral ized material has been removed from the ore. Thus, ore is not in-cluded in inventory unti l i t has been processed through the concentrator and is ready for deliv-ery to the smelter. This practice evolved because the amounts of broken ore before theconcentrating process ordinari ly are relatively small, and consequently the cost of that ore andof concentrate in process general ly is not signif icant. Furthermore, the amount of broken oreand concentrate in process is relatively constant at the end of each month, and the concentrat-ing process is quite rapid—usual ly a matter of hours. In the case of leach operations, general lythe mineral content of the ore is estimated and costs are inventoried. However, practice variesand some companies do not inventory costs unti l the leached product is introduced into theelectrochemical refinery cells.

Determining inventory quanti ties during the production process is of ten dif f icult. Brokenore, crushed ore, concentrate, and materials in process may be stored in various ways or en-closed in vessels or pipes.

With few exceptions, mining companies carry metal inventory at the lower of cost or mar-ket value, with cost determined on a last-in, f i rst out (LI FO), fi rst-in, f i rst out (FIFO), or av-erage basis. Occasional ly, mining companies value inventories of precious metals in finishedand salable form at net real izable value, which approximates market but exceeds cost. Al-though this pol icy is acceptable, it is rarely appl ied, and then only if there is an assured marketat quoted prices.

Valuation of product inventory is also af fected by worldwide imbalances between supplyand demand for certain metals. Companies sometimes produce larger quanti ties of a metal thancan be absorbed by the market. In that situation, management may have to wri te the inventorydown to its net real izable value; determining that value, however, may be dif f icult if there is noestabl ished market or only a thin market for the particular metal.

Product costs for mining companies usual ly reflect al l normal and necessary expendituresassociated with cost centers such as mines, concentrators, smelters, and refineries. Inventorycosts comprise not only direct costs of production, but also an al location of overhead, includ-ing mine and other plant administrative expenses. Depreciation, depletion, and amortizationof capital ized exploration, acquisition, and development costs also should be included ininventory.

If a company engages in tol l ing [described in subsection 24.8(b)], it may have signif icantproduction inventories on hand that belong to other mining companies. Usual ly i t is not


possible to physical ly segregate inventories owned by others from similar inventories owned bythe company. Memorandum records of tol l ing inventories should be maintained and reconciledperiodical ly to physical counts.

(ii) Materials and Supplies. Materials and suppl ies usual ly consti tute a substantial portionof the inventory of most mining companies, sometimes exceeding the value of metal invento-ries. This is because a lack of suppl ies or spare parts could cause the curtailment of operations.In addition to normal operating suppl ies, materials and suppl ies inventories of ten include suchitems as fuel and spare parts for trucks, locomotives, and other machinery. Occasional ly, be-cause of the signif icance of the cost of certain spare parts and the need to have them on handto ensure the uninterrupted operation of production equipment, mining companies capital izespare parts and treat them as equipment (accounting for them as “emergency spare parts” or“ insurance spares”) rather than inventory. These emergency spare parts are depreciated overthe same period as the equipment with which they are associated. Most mining companies useperpetual inventory systems to account for materials and suppl ies because of their high unitvalue.

Materials and suppl ies inventories normally are valued at cost minus a reserve for surplusitems and obsolescence.

(d) COMMODITIES, FUTURES TRANSACTIONS. Mining companies usual ly have signif-icant inventories of commodities that are traded in worldwide markets, and frequently enterinto long-term forward sales contracts specifying sales prices based on market prices at timeof delivery. To protect themselves from the risk of loss that could result from price declines,mining companies of ten “hedge” against price changes by entering into futures contracts.Companies sell contracts when they expect sell ing prices to decline or are satisf ied with thecurrent price and want to “lock in” the prof i t (or loss) on the sale of their inventory. To estab-l ish a hedge when it has or expects to have a commodity (e.g., copper) in inventory, a companysells a contract that commits it to deliver that commodity in the future at a fixed price. Thecompany usual ly closes out the futures position at or near the delivery date of the hedge inven-tory by buying the contract back at the current market price.

The accounting for commodity futures contracts depends on whether the contract qual if iesas a hedge under Statement of Financial Accounting Standards No. 80, Accounting for FuturesContracts (SFAS 80) (Accounting Standards Section F80). In order for the contract to qual if yas a hedge two conditions must be met: 1) the item to be hedged must expose the company toprice or interest rate risk; and 2) the contract must reduce that exposure and must be desig-nated as a hedge. In determining its exposure to price or interest rate risk, a company musttake into account other assets, liabil i ties, fi rm commitments, and anticipated transactions thatmay al ready of fset or reduce the exposure. Moreover, SFAS 80 prescribes a correlation test be-tween the hedged item and the hedging instrument that requires a company to examine histori-cal relationships and to monitor the correlation af ter the hedging transaction was executed,thus permitting cross hedging provided there is high correlation between changes in the valuesof the hedged item and the hedging instrument.

For contracts which qual if y as hedges, unreal ized gains and losses on the futures contractsare general ly deferred and are recognized in the same period in which gains or losses from theitems being hedged are recognized. Speculative contracts, in contrast, are accounted for atmarket value.

In 1992, the FASB ini tiated a project on hedge accounting and accounting for derivativesand synthetic instruments. As this publ ication goes to print, the FASB had issued an expo-sure draf t, “Accounting for Derivatives and Similar Financial I nstruments and Hedging Ac-tivi ties.” I n order to qual if y for hedging of mineral reserves, management wil l be required todetermine how it measures hedge effectiveness and to formally document the hedging rela-tionship and the enti ty’s risk management objective and strategy for undertaking the hedge.Such documentation wil l include identif ication of the hedging instrument, the related hedged


i tem, the nature of the risk being hedged, and how the hedging instrument’s effectiveness inof fsetting the exposure to changes in the hedged item’s fair value attributable to the hedgedrisk wil l be assessed.

At i ts December 19, 1997 meeting, the FASB tentatively decided that the standard would beeffective for fiscal years beginning af ter June 15, 1999, that is, for calendar year companies,the standard would be effective as of January 1, 2000. The final standard is currently expectedto be issued within the fi rst six months of 1998.

As an intermediate measure, prior to the final ization of rules related to accounting forhedges, derivatives, and synthetic instruments, the FASB decided in December 1993 to under-take a short-term project aimed at improving financial statement disclosures about derivatives.This short-term project led to the issuance of FASB Statement 119 in October 1994, enti tled“ Disclosure about Derivative Financial I nstruments and Fair Value of Financial I nstruments”(SFAS 119).

SFAS 119 requires companies to disclose the fol lowing:

• The face amount of the contract by class of f inancial instrument;

• The nature and terms of the contract, including a discussion of the credit and marketrisks and cash requirements of those instruments; and

• Their related accounting pol icy.

With respect to hedging transactions, new disclosures include: a discussion of the company’sobjectives and strategies for holding or issuing these instruments; and descriptions of howthose instruments are reported in the financial statements.

Additional ly, disclosures for hedges of anticipated transactions have been expanded to re-quire: a description of the hedge, the period of t ime the transaction is expected to occur, anddeferred gains or losses. Contracts that ei ther require the exchange of a financial instrumentfor a nonfinancial commodity or permit settlement of an obl igation by delivery of a nonfinan-cial commodity are exempt from disclosure requirements of this statement. However, depend-ing upon the signif icance of use of derivatives by particular companies, additional disclosuremay be prudent to accurately portray the manner in which the enti ty protects itself againstprice fluctuations.

(e) ENVIRONMENTAL CONCERNS. Mining operations and exploration activi ties are sub-ject to governmental regulation for the protection of the environment. These laws are continu-al ly changing and are becoming more restrictive. The primary basis for regulation ofenvironmental contamination, hazardous waste disposal, and cleanup are:

• The Resource Conservation and Recovery Act of 1976 (RCRA), which regulates the gen-eration, treatment, storage, and disposal of both sol id and hazardous wastes.

• The Comprehensive Environmental Response, Compensation and Liabil i ty Act of 1980(CERCLA or Superfund), which addresses the nationwide risk to human health and theenvironment created by inactive hazardous waste landfi l ls and contaminated sites, focus-ing on the cleanup of existing hazardous waste and dump sites.

In addition to the aforementioned federal regulations, virtual ly al l states have enacted similarregulations.

Each of the these regulations could have a signif icant impact on any mining company. How-ever, Superfund activi ties remain in the limelight largely because of the signif icant costs asso-ciated with the related remediation. To date, the Environmental Protection Agency (EPA) hasidentif ied 27,000 to 30,000 potential Superfund sites. Some have estimated the cleanup costsat $25 mil l ion per site. Experts predict that this could produce a total l iabil i ty for past contam-ination of $500 bil l ion.


Statement of Position (SOP) 96-1, Environmental Remediation Liabilit ies, provides ac-counting guidance for cleanup costs incurred under Superfund and other pol lution controllaws and regulations. SOP 96-1 is particularly relevant to auditing a mining company’s ac-counting for and disclosure of environmental l iabil i ties. It requires environmental remedia-tion liabil i ties to be accrued when the cri teria of SFAS No. 5, Accounting for Contingencies,are met, and includes benchmarks to aid in determining when such liabil i ties should be rec-ognized. It provides guidance on the recognition, measurement, display, and disclosure of en-vironmental remediation liabil i ties. The SOP also includes a nonauthori tative section onpol lution control and environmental remediation liabil i ty laws and regulations.

The SOP provides guidance only on accounting for and auditing environmental remediationl iabil i ties; it does not provide guidance on accounting for pol lution control costs with respectto current operations, for costs of f uture site restoration or closure that are required upon thecessation of operations or sale of facil i ties, or for environmental remediation undertaken atthe sole discretion of management. Also, it does not provide guidance on recognizing liabil i tiesof insurance companies for unpaid environmental cleanup-related claims or address asset im-pairment issues.

(f ) SHUT-DOWN OF MINES. As a result of environmental considerations, mining com-panies may incur signif icant costs for restoration, reclamation, and rehabil i tation of mining fa-cil i ties af ter the mining process has been completed. Those costs should be accrued during therevenue-producing period.

Volati le metal prices may make active operations uneconomical f rom time to time, and, as aresult, mining companies wil l shut down operations, ei ther temporari ly or permanently. Whenoperations are temporari ly shut down, a question arises as to the carrying value of the relatedassets. If a long-term diminution in the value of the assets has occurred, a wri te-down of thecarrying value to net real izable value should be recorded. This decision is extremely judgmen-tal and depends on projections of whether viable mining operations can ever be resumed.Those projections are based on signif icant assumptions as to prices, production, quanti ties,and costs; because most minerals are worldwide commodities, the projections must take intoaccount global supply and demand factors.

When operations are temporari ly shut down, the related facil i ties usual ly are placed in a“standby mode” that provides for care and maintenance so that the assets wil l be retained ina reasonable condition that wil l facil i tate resumption of operations. Care and maintenancecosts are usual ly recorded as expenses in the period in which they are incurred. Examples oftypical care and maintenance costs are securi ty, preventive and protective maintenance, anddepreciation.

A temporary shutdown of a mining company’s facil i ty can raise questions as to whether thecompany can continue as a going concern.

(g) ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS. The FASB is-sued a standard in March 1995 on Accounting for the Impairment of Long-Lived Assets andLong-Lived Assets To Be Disposed Of. The Standard is effective for financial statements forf iscal years beginning af ter December 15, 1995. This statement provides defini tive guidanceon when the carrying amount of long-lived assets should be reviewed for impairment. It alsoestabl ishes a common methodology for assessing and measuring the impairment of long-livedassets. Additional ly, assets to be disposed of which do not qual if y as a segment wil l now beaccounted for under the provisions of this statement.

The Standard requires long-lived assets held and used by an enti ty (e.g. plant and equipmentand capital ized exploration and development costs) to be reviewed for impairment wheneverevents or changes indicate that the carrying value of the assets may not be recoverable. In thecase of mining companies, events such as fal l ing commodity prices, increasing environmentall iabil i ties and operating costs and reductions in reserves are circumstances indicating thatlong-lived assets may be impaired.

24.8 ACCOUNTING FOR MINING REVENUES 24 • 21

The proposed test for recoverabil i ty involves a two-step approach. First, a comparison ofcarrying values of long-lived assets to the undiscounted estimated future cash flows expectedto result from their use or eventual disposition, is to be performed. If asset carrying values aregreater than such cash flows, an impairment loss would be recognized immediately. The sec-ond step involves measuring the amount of the impairment loss which is the amount by whichthe carrying amount of the asset exceeds the fair value of the asset. Fair value of assets shal lei ther be measured by their market value or sell ing prices of similar assets. If no market priceis available, then fair value is based on discounted future cash flows. The use of discountedcash flows in the measurement cri teria would therefore result in larger asset wri tedowns thanthe ini tial test for impairment would indicate.

It is important for mining companies to perform a real istic analysis of estimated future cashf lows when reviewing assets for impairment, especial ly in view of the fact that restoration ofpreviously recognized impairment losses is prohibi ted and that impairment measurement wil lresult in a larger wri tedown under the standard. In this regard, the estimate of cash flows is tobe management’s best estimate based on reasonable supportable assumptions and projections.The use of commodity prices (e.g. futures prices) other than spot would be permissible provid-ing they are reasonable and supportable.

24.8 ACCOUNTING FOR MINING REVENUES

(a) SALES OF MINERALS. General ly, minerals are not sold in the raw-ore stage because ofthe insignif icant quanti ty of minerals relative to the total volume of waste rock. (There are,however, some exceptions, such as iron ore and coal.) The ore is usual ly mil led at or near themine site to produce a concentrate containing a signif icantly higher percentage of mineral con-tent. For example, the metal content of copper concentrate typical ly is 25 to 30%, as opposedto between one-hal f and 1% for the raw ore. The concentrate is frequently sold to other proces-sors; occasional ly, mining companies exchange concentrate to reduce transportation costs.Af ter the refining process, metal l ic minerals may be sold as finished metals, ei ther in the formof products for remelting by f inal users (e.g., pig iron or cathode copper) or as finished prod-ucts (e.g., copper rod or aluminum foil ).

Sales of raw ore and concentrate entail determining metal content based ini tial ly on esti-mated weights, moisture content, and ore grade. Those estimates are subsequently revised,based on the actual metal content recovered from the raw ore or concentrate, or settlement isbased on actual recoveries. Estimates general ly are made by both the seller and the buyer; thedif ference is usual ly spl i t.

Sales prices are of ten based on the market price on a commodity exchange such as theCOMEX (New York Commodity Exchange) or LME (London Metal Exchange) at the time ofdelivery. Sometimes a time other than delivery is used to set the price; for example, the aver-age of daily COMEX prices for the two-week period subsequent to delivery of the mineralscould be used. In those circumstances, it might be necessary to record revenue based on an es-timate of the total sales value of the shipment at the point of sale and adjust the amount whenthe sales price has been determined.

General ly, revenue should be recognized only when al l of the fol lowing conditions havebeen met:

• The product has been shipped and is no longer under physical control of the seller (or ti tleto the product has al ready passed to the buyer);

• The quanti ty and qual i ty of the product can be determined with reasonable accuracy; and

• The sell ing price can be determined with reasonable accuracy.

Mining companies of ten encounter problems with the last two conditions because final quanti-ties and prices may not be establ ished at the time of delivery. Provisional invoices commonly


are recorded using estimated quanti ties and prices that are adjusted when details of the deliv-eries are final ized.

(b) TOLLING AND ROYALTY REVENUES. Companies with smelters and refineries may alsoreal ize revenue from tol l ing, which is the processing of metal-bearing materials of other miningcompanies for a fee. The fee is based on numerous factors, including the weight and metal con-tent of the materials processed. Normally, the processed minerals are returned to the originalproducer for subsequent sale. To supplement the recovery of f ixed costs, companies withsmelters and refineries frequently enter into tol l ing agreements when they have excess capacity.

For a variety of reasons, companies may not wish to mine certain properties that they own.Mineral royalty agreements may be entered into that provide for royalties based on a percent-age of the total value of the mineral or of gross revenue, to be paid when the minerals extractedfrom the property are sold.

24.9 SUPPLEMENTARY FINANCIAL STATEMENTINFORMATION—ORE RESERVES

SFAS No. 89, “Financial Reporting and Changing Prices” (Accounting Standards Section C28),eliminated the requirement that certain publ icly t raded companies meeting specif ied size cri te-ria must disclose the effects of changing prices and supplemental disclosures of ore reserves.However, Item 102 of Securi ties and Exchange Commission Regulation S-K requires thatpubl icly t raded mining companies present information related to production, reserves, loca-tions, developments, and the nature of the registrant’s interest in properties.

24.10 ACCOUNTING FOR INCOME TAXES

Chapter 19 addresses general accounting for income taxes. Tax accounting for oil and gas pro-duction as well as hard rock mining is particularly complex and cannot be fully covered in thischapter. However, two special deductions need to be mentioned—percentage depletion and im-mediate deduction of certain development costs.

Many petroleum and mining production companies are al lowed to calculate depletion as thegreater of cost depletion or percentage depletion. Cost depletion is based on amortization ofproperty acquisition costs over estimated recoverable reserves. Percentage depletion is a statu-tory depletion deduction that is a specif ied percentage of gross revenue at the well-head ormine (15% for oil and gas) for the particular mineral produced and is limited to a portion ofthe property’s taxable income before deducting such depletion. Percentage depletion may ex-ceed the depletable cost basis.

The determination of gross income from mining is based on the value of the mineral at thecutof f point (i.e., before appl ication of nonmining processes). To the extent that minerals aresold to independent third parties at the cutof f point, the sales price general ly determines grossincome from mining. For an integrated mining company, gross income should be determined byusing a representative field or market price for an ore or mineral of similar kind of grade. Ab-sent such price, gross income can be determined under the proportionate prof i ts method, whichattributes an equal amount of prof i t to each dol lar of mining and nonmining cost incurred.

For both petroleum and mining companies, exploration and development costs other thanfor equipment are largely deductible when incurred. However, al l mining companies and themajor, integrated petroleum companies must capital ize 30% of such exploration and develop-ment costs and amortize that portion over 60 months. Mining companies must also recapturethe previously deducted exploration costs when and if the related mine attains commercialproduction.

24.12 SOURCES AND SUGGESTED REFERENCES 24 • 23

24.11 FINANCIAL STATEMENT DISCLOSURES

The SFAS No. 69 details supplementary disclosure requirements for the oil and gas industry,most of which are required only by publ ic companies. Both publ ic and nonpubl ic companies,however, must provide a description of the accounting method fol lowed and the manner of dis-posing of capital ized costs. Audited financial statements fi led with the SEC must include sup-plementary disclosures, which fal l into four categories:

• Historical cost data relating to acquisition, exploration, development, and productionactivi ty.

• Results of operations for oil- and gas-producing activi ties.

• Proved reserve quanti ties.

• Standardized measure of discounted future net cash flows relating to proved oil and gasreserve quanti ties (also known as SMOG [standardized measure of oil and gas]). For for-eign operations, SMOG also relates to produced quanti ties subject to certain long-termpurchase contracts held by a party involved in producing the quanti ties.

The supplementary disclosures are required of companies with signif icant oil- and gas-producing activi ties; signif icant is defined as 10% or more of revenue, operating results, oridentif iable assets. The statement provides that the disclosures are to be provided as supple-mental data; thus they need not be audited. The disclosure requirements are described indetail in the statement, and examples are provided in an appendix to SFAS No. 69. If the sup-plemental information is not audited, it must be clearly labeled as unaudited. However, audit-ing interpretations (Au Section 9558) required the financial statement auditor to performcertain limited procedures to these required, unaudited supplementary disclosures.

Proved reserves are inherently imprecise because of the uncertainties and limitations of thedata available.

Most large companies and many medium-sized companies have qual if ied engineers ontheir staf fs to prepare oil and gas reserve studies. Many also use outside consultants to makeindependent reviews. Other companies, who do not have suff icient operations to justif y a full-time engineer, engage outside engineering consultants to evaluate and estimate their oil andgas reserves. Usual ly, reserve studies are reviewed and updated at least annual ly to take intoaccount new discoveries and adjustments of previous estimates.

The standardized measure is disclosed as of the end of the fiscal year. The SMOG reflectsfuture revenues computed by applying unescalated, year-end oil and gas prices to year-endproved reserves. Future price changes may only be considered if f ixed and determinable underyear-end sales contracts. The calculated future revenues are reduced for estimated futuredevelopment costs, production costs, and related income taxes (using unescalated, year-endcost rates) to compute future net cash flows. Such cash flows, by future year, are discounted ata standard 10% per annum to compute the standardized measure.

Signif icant sources of the annual changes in the year-end standardized measure and year-end proved oil and gas reserves should be disclosed.

24.12 SOURCES AND SUGGESTED REFERENCES

Brock, Horace R., Jennings, Dennis R., and Fei ten, Joseph B., Petroleum Accounting—Pr inciples, Proce-dures, and Issues, 4th ed.. Professional Development Insti tute, Denton, TX, 1996.

Counci l of Petroleum Accountants Societies, Bulletin No. 24, Producer Gas Imbalances as revised. Kraf t-bil t Products, Tulsa, 1991.

Ell is, Richard W., McCarthy, Dennis J., and Skidmore, Constance E., Financial Repor ting and Tax Prac-tices In Nonferrous Mining, 18th ed. Coopers & Lybrand L.L.P., New York, 1995..

ninth edition accountants’ handbook · 2020. 8. 16. · volume one: financial accounting and...

Documents