II. Guidance About Disclosures

A. General Guidance About New Accounting Standards

> 1. BEFORE ADOPTION BY THE REGISTRANT

Staff Accounting Bulletin 74 (Topic 11:M) discusses disclosures that a registrant should provide in its financial statements and/or MD&A regarding the impact that recently issued accounting standards will have on its financial statements when the standard is adopted in a future period. Disclosures that should be considered include a brief description of the standard and its anticipated adoption date, the method by which the standard will be adopted, the impact that the standard will have on the financial statements to the extent reasonably estimable, and any other effects that are reasonably likely to occur (e.g., changes in business practices, changes in availability or cost of capital, violations of debt covenants, etc.). In this regard, registrants should consider the effects of not only standards recently issued by the FASB, but also Statements of Position and Practice Bulletins issued by the AICPA and consensus positions of the EITF.

> 2. ADOPTION OF NEW STANDARD IN INTERIM PERIOD

Rule 10-01(a)(5) of Regulation S-X permits registrants to omit from interim reports on Form 10-Q footnote disclosures that would be repetitive of information included in the annual financial statements, except that disclosures about material contingencies must always be furnished. The rule also indicates that if events occur subsequent to the fiscal year-end, such as a change in accounting principles and practices, informative disclosure shall be made. Registrants should describe the accounting change and its impact pursuant to APB 28, as amended by SFAS 3. In addition, the staff believes the interim financial statements should include, to the extent applicable, all disclosures identified by the adopted standard as required to be included in annual financial statements. If the change in accounting principle is made in a period other than the first quarter of the year, no amendment of prior filings is required; however, a restatement of each of the prior quarter's results should be included in the filing for the quarter in which the new accounting principle is adopted pursuant to SFAS 3. If the new accounting principle is applied retroactively to prior years, the prior comparable interim quarters should be presented on a restated basis also.

B. Disclosures Regarding the Realization of a Deferred Tax Asset

SFAS 109 ("Accounting for Income Taxes") requires recognition of future tax benefits attributable to tax net loss carryforwards and deductible temporary differences between financial statement and income tax bases of assets and liabilities. Deferred tax assets must be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the benefits will not be realized. Notes to financial statements must disclose the amount of the valuation allowance and changes therein.

If a registrant has recognized a net deferred tax asset that is material, it may be necessary to discuss uncertainties surrounding realization of the asset and material assumptions underlying management's determination that the net asset will be realized. If the asset's realization is dependent on material improvements over present levels of consolidated pre-tax income, material changes in the present relationship between income reported for financial and tax purposes, or material asset sales or other nonroutine transactions, a description of these assumed future events, quantified to the extent practicable, should be furnished in the MD&A. For example, the minimum annualized rate by which taxable income must increase during the tax NOL carryforward period should be disclosed if realization of the benefit is dependent on taxable income higher than currently reported. Also, if significant objective negative evidence indicates uncertainty regarding realization of the deferred asset, the countervailing positive evidence relied upon by management in its decision not to establish a full allowance against the asset should be identified.

Conversely, a valuation allowance for the deferred tax asset is not appropriate unless it is more likely than not that the asset will not be realized. The staff has challenged registrants that establish a significant allowance but whose disclosures regarding current and expected operating results appear inconsistent with management's view regarding realization of the deferred tax asset. In those circumstances, the staff has questioned whether the narrative disclosures are unreasonably optimistic or the valuation allowance is unreasonably pessimistic, and revisions to the financial statements or the narrative typically have been necessary to reconcile the apparent inconsistency.

Material changes in the allowance for realization of a deferred tax asset from one period to the next should be fully explained in MD&A, highlighting changes in assumptions and environmental factors that necessitated the change.

C. Disclosure of Non-GAAP Measures Such as "EBITDA"

Some registrants choose to present a non-GAAP financial measure such as EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) or FFO (funds from operations) in their disclosure documents. Although such measures can be useful in some circumstances, an unbalanced presentation can be confusing and lead to undue reliance on the measure by investors. Problems associated with presentations of non-GAAP measures were highlighted by the Commission in Accounting Series Release No. 142. Some comments cited frequently by the staff include the following:

A non-GAAP measure should be presented in a manner that does not give it greater authority or prominence than conventionally computed earnings or cash flows as reported in the GAAP financial statements. For example, the staff recommends that EBITDA and similar measures be located within an "other data" section in selected financial data. Discussions in MD&A of results as measured in the GAAP financial statements should be no less complete than discussions of performance or liquidity as depicted by non-GAAP measures.
Wherever the non-GAAP measure is used, a footnote or other reference to a complete explanation of its calculation and components should be provided. Since all companies and analysts do not calculate these non-GAAP measures in the same fashion, the staff recommends that the footnote or other disclosure alert investors to the fact that the measure presented may not be comparable to similarly titled measures reported by other companies.
Management should consider how any non-GAAP measure is expected to be used by investors, identify significant factors that should be considered, and discuss significant trends or requirements not captured by the measure to ensure balance and avoid undue reliance on the measure. Notwithstanding disclosures by competitors or requests from financial analysts, the staff believes that non-GAAP measures generally should be avoided unless management itself believes that the measure provides relevant and useful information.
Non-GAAP measures that measure cash or "funds" generated by operations (liquidity) should be balanced with equally prominent disclosure of amounts from the statement of cash flows (cash flows from operations, investing and financing activities) and, in some cases, the ratio or deficiency of earnings to fixed charges. Explanation may be necessary to the extent that funds depicted by the measure are not available for management's discretionary use (due to legal or functional requirements to conserve funds for capital replacement and expansion, debt service and balloon maturities, deferred interest and dividend payments, and other commitments and uncertainties).
A frequent disclosure issue is the use of a non-GAAP measure in a discussion of operating performance when the measure is primarily a measure of liquidity, capital resources, or debt service capacity. For example, calculations that depict an adjusted or normalized measure of working capital or funds generated by operations and available to meet capital and debt requirements often are presented inappropriately as if they should be used as alternative measures of earnings, return on investment or similar performance or efficiency factors. In that case, the staff will request the measure's presentation in an appropriate context with clarification of its expected use.
If management is presenting the non-GAAP calculation as an alternative or pro forma measure of performance, the staff discourages adjustments to eliminate or smooth items characterized as nonrecurring, infrequent or unusual. Different unusual items are likely to occur every period, and companies and investors may differ as to what types of events warrant adjustment. Trends may be distorted and disclosure unbalanced if only certain items are adjusted while the effects of other infrequent events or transactions (whether favorable or unfavorable) are not considered or highlighted. Of course, all such special items should be highlighted in the registrant's disclosures to permit analysis by investors. Where management intends the measure to be indicative of liquidity and communicates that use through the context of its presentation, the staff ordinarily will not object to adjustment for non-cash charges relating to special items if it is meaningful to investors in the circumstances.

D. Disclosures by Issuers of "Targeted Stock"

> OVERVIEW

Some registrants have issued classes of stock which they characterize as "targeted" or "tracking" stock because they are referenced in some manner to a specific business unit, activity or assets of the registrant. The staff is concerned that the style and content of disclosures about the operations referenced by a class of common stock may give the inaccurate impression that the investor has a direct or exclusive financial interest in that unit.

Notwithstanding the title given to a particular class of stock, an investor in any of a registrant's classes of common stock has a financial interest only in the residual net assets of the registrant, allocated among the shareholder classes in accordance with the formulae stipulated in the corporate charter. Assets and income attributed to units referenced by each class typically are available to all of the registrant's creditors, and even other classes of shareholders, in the event of liquidation. While dividends declared on each class may not exceed some measure of the performance of the referenced business unit, no dividends need be declared at all. Moreover, the dividend declaration policies typically are subject to change and need bear no relationship to the relative performance of the referenced businesses. Methods and assumptions that can significantly affect measurement of the referenced unit's performance typically can be changed at any time without the consent of the security holders.

> CHARACTERIZATIONS OF THE SECURITY AS "TRACKING" A BUSINESS UNIT

If no term of the targeted stock requires or assures that potential distributions will correlate with the performance of the business unit nominally associated with the security, implications that the market value of the security will "track," or is otherwise linked with, a business unit are subject to challenge. The staff has asked registrants to explain in their filings why the formula for determining the amount available for dividends (or any other term or feature of the security) can be expected to link in some fashion the market value of a class of common stock with the value or performance of any subpart of the registrant, or state clearly that management does not intend to imply such a linkage.

> RECOMMENDED APPROACH TO DISCLOSURE ABOUT TARGETED STOCK

While the staff encourages robust disclosure about the registrant's operating segments, presenting information about the referenced businesses as if distinct from the registrant may confuse investors about the nature of the security. We believe companies should integrate discussions and quantitative data about the referenced business units more closely within a comprehensive discussion of the registrant's financial condition and operating results. While schedules or condensed financial information demonstrating the calculation of earnings available for each class of the registrant's common stock are relevant, more extensive presentations can be misunderstood and should be reconsidered. If a company chooses to present more than condensed financial data, the staff has recommended that companies present no greater detail than "consolidating financial statements" that include the referenced businesses together with the financial statements of the registrant. That presentation would show explicitly how management and the board have allocated and attributed revenues, expenses, assets, liabilities, and cash flows, but will not necessarily reflect earnings applicable to the different classes of stock due to features of the allocation formula which are incompatible with GAAP.

> USE OF SEPARATE FULL FINANCIAL STATEMENTS FOR A REFERENCED BUSINESS UNIT

Notwithstanding our recommendation to the contrary, some issuers of targeted stock have chosen to present complete separate audited financial statements of the referenced units. In this case, the staff believes that financial statements of the referenced unit furnished to investors should be accompanied always by financial statements of the registrant, as issuer of the security. Most auditors will permit use of their report on the financial statements of the referenced business only in those circumstances. EPS of one class of stock should not be presented alone or within the separate financial statements of the referenced business security because that business did not issue the security. EPS with respect to any class of the issuer's securities should be presented only with the issuer's consolidated financial statements or with its related consolidated information.

> CONSEQUENCES OF FORMULA-BASED FINANCIAL STATEMENTS

In some cases, separate financial statements presented in an issuer's filing do not appear to be an actual business or division, but rather an elaborate depiction of the earnings allocation formula for a class of stock, as if those legal terms defined an accounting entity. For example, sometimes that formula results in the depiction of one of the issuer's businesses as if it had a financial interest in another of its businesses. Financial statements prepared in accordance with the dictates of management, the board and the corporate charter for the purpose of measuring earnings available to a class of shareholders do not necessarily present fairly the financial condition, cash flows and operating results of an actual business unit within the registrant.

The staff has raised a number of questions in these circumstances: Do financial statements based on these formulae comply with GAAP? Does the association of the auditor with these presentations give unwarranted comfort to investors about the fairness to the different shareholder groups of management's assignment of revenues and expenses and its allocation of capital and other costs. Are the financial statements "special purpose" financial statements that are prepared on a basis of accounting prescribed in a contractual agreement, requiring special considerations for disclosure and auditor association?

> NON-GAAP MEASURES OF PERFORMANCE

In some cases, the terms of the targeted stock stipulate explicitly that the performance of the unit will be measured on a basis that departs from GAAP. Any measurement, classification, allocation or disclosure that departs from GAAP but is necessary to measure or explain amounts available for dividends on stock referenced to the unit should be depicted separately from presentations that are purported to be in accordance with GAAP. An amount should not be labeled as "net income" unless it is calculated in accordance with GAAP. If the financial statements of the unit are purported to be in accordance with GAAP, management should ensure that all information essential for a fair presentation of the entity's financial position, results of operations, and cash flows in conformity with GAAP is set forth in the financial statements. Failure to include all such information should result in a qualification of the auditor's report on the unit's financial statements.

> COST ALLOCATIONS

The units referenced by the targeted stock may share many common costs, such as general and administrative and interest costs. As required by SAB Topic 1B, a complete description of any allocation methods used for cash, debt, related interest and financing costs, corporate overhead, and other common costs should be provided in the notes to the financial statements that purport to be prepared in accordance with GAAP. The amounts likely to be reported by the entity were it a stand-alone entity should be disclosed. In some cases, the staff has questioned whether allocations have been biased. For example, operating results and EPS of operations that are valued on the basis of earnings could be unfairly inflated as a result of excessive allocations of common costs to operations that are valued on the basis of revenue growth. If the methodologies and assumptions underlying the allocations of debt and corporate expenses may change without securityholder approval, that fact should be stated clearly. If the financial statements of the business unit before and after the issuance of the tracking stock will not be comparable, that fact should be disclosed. On occasion, the staff has questioned whether a change in the method of attributing revenue or expense from one shareholder group to another would be reported as a change in reporting entity or, if deemed a change in estimate or principle, how the auditor will determine whether a change is a "better" method of calculating earnings attributable to a particular shareholder group.

> OTHER DISCLOSURE ISSUES

Other areas of disclosure that are of particular significance for issuers of targeted stock include the following:

Policies for the management of cash generated by and capital investment in the referenced units, and for the pricing of "transactions" between the referenced units.
- Conflicts of interest.
- Effects of corporate events (mergers, tender offers, changes in control, adverse tax rulings, liquidation) on rights of the security holders.
- Terms under which one class may be converted into another class.
- Effects of changes in relative market values of the registrant's outstanding classes of stock on rights of the security holders.

E. Disclosures by Electric Utilities

Electric utility companies are facing increasing competition. The regulatory framework in which they operate is undergoing significant change, although the path and pace of that change vary from jurisdiction to jurisdiction. Clear and balanced disclosure is necessary to inform investors about the specific risks and uncertainties that are reasonably likely to affect the reporting company. Consequences of the competitive and regulatory changes may include impairment of significant recorded assets, material reductions of profit margins, and increased costs of capital. Those risks, quantified to the extent practicable, should be discussed in MD&A.

Many regulated utilities account for costs differently from other public companies. Under SFAS 71, a utility may defer certain costs of providing services if the rates established by its regulators are designed to recover the utility's specific costs and the economic environment gives reasonable assurance that those rates can be charged and collected throughout the periods necessary to recover the costs. When a utility ceases to operate under those conditions, significant costs previously deferred under SFAS 71 as regulatory assets must be written off and methods of amortizing capital assets must be revised to conform with lives appropriate in a competitive environment. The resulting reduction in reported equity and operating margin, accompanied by the increased market risks, may create new requirements for equity capital and push borrowing costs higher. While some companies may be affected only marginally in the next several years, others may suffer serious financial consequences.

Disclosures responsive to Item 101 (Description of Business) of Regulation S-K include a description of the competitive conditions faced by the registrant and material features of its regulatory environment. Item 303 (Management's Discussion and Analysis) requires meaningful explanation of how changes in competition and rate setting practices have affected or are reasonably likely to affect operating results. If recovery of identifiable categories of capital assets, regulatory assets or other deferred costs is subject to material uncertainties, quantitative disclosure is warranted.

For example, if the registrant has submitted information to state and/or federal regulators in an effort to implement special rate and/or depreciation plans, the staff believes that a description of those plans, including the type and amount of potentially "stranded" costs identified in those plans, should be discussed in MD&A. Potentially stranded investments and costs commonly include differences between regulatory accumulated depreciation for plant and the accumulated depreciation which would have been recorded based on generally accepted accounting principles, and expected or estimated differences between the carrying amount of plant assets and the amount that would be recoverable in a deregulated environment.

Avoiding boilerplate or overly general disclosures, the registrant should identify specific segments or customer classes that are most likely to be affected by regulatory or competitive changes, and describe clearly how specific assets, revenues and operating margins may be affected. For example, registrants should disclose the relative proportion of operations affected by special non-traditional rate plans with specific groups of customers, including industrial customers, and quantify to the extent practicable the current and expected impact of those arrangements. Regulatory developments and uncertainties unique to individual significant jurisdictions should be highlighted, and any material effects that are reasonably likely to occur should be discussed and quantified. Required disclosures in financial statements about accounting policies governing cost deferral and depreciation may warrant additional explanation in MD&A if unique or unusual practices materially affect reported results or the loss of eligibility to use the accounting method is reasonably likely and would have a material effect.

F. Issues in the Extractive Industries

> 1. MINING EXPLORATION COSTS

Recoverability of capitalized costs is likely to be insupportable under FASB Statement No. 121 prior to determining the existence of a commercially minable deposit, as contemplated by Industry Guide 7 for a mining company in the exploration stage. As a result, the staff would generally challenge capitalization of exploration costs, and believes that those costs should be expensed as incurred during the exploration stage under US GAAP.

> 2. ACCOUNTING FOR INVENTORIES ABOVE COST

Only in exceptional cases may inventory properly be stated at an amount above cost. Accounting Research Bulletin (ARB) No. 43, Restatement and Revision of Accounting Research Bulletins, cites the exceptional example of precious metals having a fixed monetary value with no substantial cost of marketing. That guidance goes on to specify criteria that must be met by any inventory carried above its cost:

inability to determine appropriate approximate costs;
immediate marketability at quoted market price; and
unit interchangeability.

Only when all these criteria are met should management consider accounting for inventory at amounts above cost. The staff believes the criteria in ARB 43 are even more rarely satisfied today than in 1953 when ARB 43 was published. For example, the availability of sophisticated cost accounting techniques and supporting software suggests that few, if any, registrants are unable to approximate the appropriate cost of inventory.

Also, the criteria of "immediately marketability" and "unit interchangeability" are not met by items that are in-process and not yet in final marketable form. For example, until precious or base metals are in the final refined state in which they are typically marketed, the items are not immediately marketable nor do they have the characteristic of unit interchangeability. Mined ore, yet to be subjected to refining or smelting processes, should not be carried at an amount above cost.

Registrants should ensure that their accounting policies for in-process inventory conform to the guidance in ARB 43. SAB 101 reminds registrants that authoritative literature takes precedence over industry practice that is contrary to generally accepted accounting principles.

> 3. DEFINITION OF PROVED RESERVES

Over the last several years, the estimation and classification of petroleum reserves has been impacted by the development of new technologies such as 3-D seismic interpretation and reservoir simulation. Computer processor improvements have allowed the increased use of probabilistic methods in proved reserve assessments. These have led to issues of consistency and, therefore, some confusion in the reporting of proved oil and gas reserves by public issuers in their filings with the Commission. This section discusses some issues the Division of Corporation Finance's engineering staff has identified in its review of such filings.

The definitions for proved oil and gas reserves for the SEC are found in Rule 4-10(a) of Regulation S-X of the Securities Exchange Act of 1934. The SEC definitions are below in bold italics. Under each section we have tried to explain the SEC staff's position regarding some of the more common issues that arise from each portion of the definitions. As most engineers who deal with the classification of reserves have come to realize, it is difficult, if not impossible, to write reserve definitions that easily cover all possible situations. Each case has to be studied as to its own unique issues. This is true with the Society of Petroleum Engineers' and others' reserve definitions as well as the SEC's definitions.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided by contractual arrangements, but not on escalations based upon future conditions.
The determination of reasonable certainty is generated by supporting geological and engineering data. There must be data available which indicate that assumptions such as decline rates, recovery factors, reservoir limits, recovery mechanisms and volumetric estimates, gas-oil ratios or liquid yield are valid. If the area in question is new to exploration and there is little supporting data for decline rates, recovery factors, reservoir drive mechanisms etc., a conservative approach is appropriate until there is enough supporting data to justify the use of more liberal parameters for the estimation of proved reserves. The concept of reasonable certainty implies that, as more technical data becomes available, a positive, or upward, revision is much more likely than a negative, or downward, revision.
Existing economic and operating conditions are the product prices, operating costs, production methods, recovery techniques, transportation and marketing arrangements, ownership and/or entitlement terms and regulatory requirements that are extant on the effective date of the estimate. An anticipated change in conditions must have reasonable certainty of occurrence; the corresponding investment and operating expense to make that change must be included in the economic feasibility at the appropriate time. These conditions include estimated net abandonment costs to be incurred and duration of current licenses and permits.
If oil and gas prices are so low that production is actually shut-in because of uneconomic conditions, the reserves attributed to the shut-in properties can no longer be classified as proved and must be subtracted from the proved reserve data base as a negative revision. Those volumes may be included as positive revisions to a subsequent year's proved reserves only upon their return to economic status.
Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limits of the reservoir.
Proved reserves may be attributed to a prospective zone if a conclusive formation test has been performed or if there is production from the zone at economic rates. It is clear to the SEC staff that wireline recovery of small volumes (e.g., 100 cc) or production of a few hundred barrels per day in remote locations is not necessarily conclusive. Analyses of open-hole well logs which imply that an interval is productive are not sufficient for attribution of proved reserves. If there is an indication of economic producibility by either formation test or production, the reserves in the legal and technically justified drainage area around the well projected down to a known fluid contact or the lowest known hydrocarbons, or LKH may be considered to be proved.
In order to attribute proved reserves to legal locations adjacent to such a well (i.e., offsets), there must be conclusive, unambiguous technical data which supports reasonable certainty of production of such volumes and sufficient legal acreage to economically justify the development without going below the shallower of the fluid contact or the LKH. In the absence of a fluid contact, no offsetting reservoir volume below the LKH from a well penetration shall be classified as proved.
Upon obtaining performance history sufficient to reasonably conclude that more reserves will be recovered than those estimated volumetrically down to LKH, positive reserve revisions should be made.
Reserves which can be produced economically through applications of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
If an improved recovery technique which has not been verified by routine commercial use in the area is to be applied, the hydrocarbon volumes estimated to be recoverable cannot be classified as proved reserves unless the technique has been demonstrated to be technically and economically successful by a pilot project or installed program in that specific rock volume. Such demonstration should validate the feasibility study leading to the project.
Estimates of proved reserves do not include the following:
- oil that may become available from known reservoirs but is classified separately as "indicated additional reserves";
- crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
- crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects;
- crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other sources.
Geologic and reservoir characteristic uncertainties such as those relating to permeability, reservoir continuity, sealing nature of faults, structure and other unknown characteristics may prevent reserves from being classified as proved. Economic uncertainties such as the lack of a market (e.g., stranded hydrocarbons), uneconomic prices and marginal reserves that do not show a positive cash flow can also prevent reserves from being classified as proved. Hydrocarbons "manufactured" through extensive treatment of gilsonite, coal and oil shales are mining activities reportable under Industry Guide 7. They cannot be called proved oil and gas reserves. However, coal bed methane gas can be classified as proved reserves if the recovery of such is shown to be economically feasible.
In developing frontier areas, the existence of wells with a formation test or limited production may not be enough to classify those estimated hydrocarbon volumes as proved reserves. Issuers must demonstrate that there is reasonable certainty that a market exists for the hydrocarbons and that an economic method of extracting, treating and transporting them to market exists or is feasible and is likely to exist in the near future. A commitment by the company to develop the necessary production, treatment and transportation infrastructure is essential to the attribution of proved undeveloped reserves. Significant lack of progress on the development of such reserves may be evidence of a lack of such commitment. Affirmation of this commitment may take the form of signed sales contracts for the products; request for proposals to build facilities; signed acceptance of bid proposals; memos of understanding between the appropriate organizations and governments; firm plans and timetables established; approved authorization for expenditures to build facilities; approved loan documents to finance the required infrastructure; initiation of construction of facilities; approved environmental permits etc. Reasonable certainty of procurement of project financing by the company is a requirement for the attribution of proved reserves. An inordinately long delay in the schedule of development may introduce doubt sufficient to preclude the attribution of proved reserves.
The history of issuance and continued recognition of permits, concessions and commerciality agreements by regulatory bodies and governments should be considered when determining whether hydrocarbon accumulations can be classified as proved reserves. Automatic renewal of such agreements cannot be expected if the regulatory body has the authority to end the agreement unless there is a long and clear track record which supports the conclusion that such approvals and renewal are a matter of course.
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or bore hole stimulation treatment would be examples of properties with proved developed reserves since the majority of the expenditures to develop the reserves has already been spent.
Proved developed reserves from improved recovery techniques can be assigned after either the operation of an installed pilot program shows a positive production response to the technique or the project is fully installed and operational and has shown the production response anticipated by earlier feasibility studies. In the case with a pilot, proved developed reserves can be assigned only to that volume attributable to the pilot's influence. In the case of the fully installed project, response must be seen from the full project before all the proved developed reserves estimated can be assigned. If a project is not following original forecasts, proved developed reserves can only be assigned to the extent actually supported by the current performance. An important point here is that attribution of incremental proved developed reserves from the application of improved recovery techniques requires the installation of facilities and a production increase.
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. (Emphasis added)
The SEC staff points out that this definition contains no mitigating modifier for the word certainty. Also, continuity of production requires more than the technical indication of favorable structure alone (e.g., seismic data) to meet the test for proved undeveloped reserves. Generally, proved undeveloped reserves can be claimed only for legal and technically justified drainage areas offsetting an existing productive well (but structurally no lower than LKH). If there are at least two wells in the same reservoir which are separated by more than one legal location and which show communication (reservoir continuity), proved undeveloped reserves could be claimed between the two wells, even though the location in question might be more than an offset well location away from any of the wells. In this illustration, seismic data could be used to help support this claim by showing reservoir continuity between the wells, but the required data would be the conclusive evidence of communication from production or pressure tests. The SEC staff emphasizes that proved reserves cannot be claimed more than one offset location away from a productive well if there are no other wells in the reservoir, even though seismic data may exist. The use of high-quality, well calibrated seismic data can improve reservoir description for performing volumetrics (e.g., fluid contacts). However, seismic data is not an indicator of continuity of production and, therefore, can not be the sole indicator of additional proved reserves beyond the legal and technically justified drainage areas of wells that were drilled. Continuity of production would have to be demonstrated by something other than seismic data.
In a new reservoir with only a few wells, reservoir simulation or application of generalized hydrocarbon recovery correlations would not be considered a reliable method to show increased proved undeveloped reserves. With only a few wells as data points from which to build a geologic model and little performance history to validate the results with an acceptable history match, the results of a simulation or material balance model would be speculative in nature. The results of such a simulation or material balance model would not be considered to be reasonably certain to occur in the field to the extent that additional proved undeveloped reserves could be recognized. The application of recovery correlations which are not specific to the field under consideration is not reliable enough to be the sole source for proved reserve calculations.
Reserves cannot be classified as proved undeveloped reserves based on improved recovery techniques until such time that they have been proved effective in that reservoir or an analogous reservoir in the same geologic formation in the immediate area. An analogous reservoir is one having at least the same values or better for porosity, permeability, permeability distribution, thickness, continuity and hydrocarbon saturations.
Topic 12 of Accounting Series Release No. 257 of the Staff Accounting Bulletins states:
In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test.
If the combination of data from open-hole logs and core analyses is overwhelmingly in support of economic producibility and the indicated reservoir properties are analogous to similar reservoirs in the same field that have produced or demonstrated the ability to produce on a conclusive formation test, the reserves may be classified as proved. This would probably be a rare event especially in an exploratory situation. The essence of the SEC definition is that in most cases there must at least be a conclusive formation test in a new reservoir before any reserves can be considered to be proved.
Statement of Financial Accounting Standards 69, paragraph 30.a. requires that "Future cash inflows . . . be computed by applying year-end prices of oil and gas relating to the enterprise's proved reserves to the year-end quantities of those reserves. This requires the use of physical pricing determined by the market on the last day of the (fiscal) year. For instance, a west Texas oil producer should determine the posted price of crude (hub spot price for gas) on the last day of the year, apply historical adjustments (transportation, gravity, BS&W, purchaser bonuses, etc.) and use this oil or gas price on an individual property basis for proved reserve estimation and future cash flow calculation (this price is also used in the application of the full cost ceiling test). A monthly average is not the price on the last day of the year, even though that may be the price received for production on the last day of the year. Paragraph 30b) states that future production costs are to be based on year-end figures with the assumption of the continuation of existing economic conditions.
Probabilistic methods of reserve estimating have become more useful due to improved computing and more important because of its acceptance by professional organizations such as the SPE. The SEC staff feels that it would be premature to issue any confidence criteria at this time. The SPE has specified a 90% confidence level for the determination of proved reserves by probabilistic methods. Yet, many instances of past and current practice in deterministic methodology utilize a median or best estimate for proved reserves. Since the likelihood of a subsequent increase or positive revision to proved reserve estimates should be much greater than the likelihood of a decrease, we see an inconsistency that should be resolved. If probabilistic methods are used, the limiting criteria in the SEC definitions, such as LKH, are still in effect and shall be honored. Probabilistic aggregation of proved reserves can result in larger reserve estimates (due to the decrease in uncertainty of recovery) than simple addition would yield. We require a straight forward reconciliation of this for financial reporting purposes.
The calculation of the standardized measure of discounted future net cash flows relating to oil and gas properties must comply with paragraph 30 of SFAS 69. The effects of income taxes, like all other elements of the measure, must be discounted at the standard rate of 10% pursuant to paragraph 30(e). The "short-cut" method for determining the tax effect on the ceiling test for companies using the full-cost method of accounting, as described in SAB Topic 12:D:1, Question 2, may not be used for purposes of the paragraph 30 calculation of the standardized measure.
We have seen in press releases and web sites disclosure language by oil and gas companies which would not be allowed in a document filed with the SEC. We will request that any such disclosures be accompanied by the following cautionary language:
Cautionary Note to U.S. Investors -- The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms {in this press release/on this web site}, such as [identify the terms], that the SEC's guidelines strictly prohibit us from including in filings with the SEC. U.S. Investors are urged to consider closely the disclosure in our Form XX, File No. X-XXXX, available from us at [registrant address at which investors can request the filing]. You can also obtain this form from the SEC by calling 1-800-SEC-0330.
Examples of such disclosures would be statements regarding "probable," "possible," or "recoverable" reserves among others.
Under Production Sharing Agreements, a host government typically retains the title to the hydrocarbons in place, although the contracting company usually assumes all the costs for exploration and carries all risks. When a discovery is made, the contract provides for the contracting company to recover all its exploration and development expenditures and receive a share of profits, subject to certain limits. The amounts due to the contracting company are typically taken in kind.
In general, two methods of determining oil and gas reserves under production sharing arrangements have been proposed by registrants: (a) the working interest method and (b) the economic interest method. Under the working interest method, the estimate for total proved reserves is multiplied by the respective working interest held by the contracting company, net of any royalty. Under the economic interest method, the company's share of the cost recovery oil revenue and the profit oil revenue is divided by the year-end oil price, which represents the volume entitlement. The lower the oil price, the higher the barrel entitlement, and vice versa.
Reserve volumes determined by various owners should add up to 100% of the total field reserves, but that is not always the case using the working interest method. If the working interest is different from the profit entitlement, the economic interest method is the method acceptable to the staff because it is a closer representation of the actual reserve volume entitlement that can be monetized by a company. Also, use of the economic interest method avoids violating the prohibition in paragraph 10 of SFAS 69 against reporting reserves owned by others.
The SEC staff reminds professionals engaged in the practice of reserve estimating and evaluation that the Securities Act of 1933 subjects to potential civil liability every expert who, with his or her consent, has been named as having prepared or certified any part of the registration statement, or as having prepared or certified any report or valuation used in connection with the registration statement. These experts include accountants, attorneys, engineers or appraisers.

> 4. GOODWILL AND PURCHASE BUSINESS COMBINATIONS

The staff often has challenged recognition of goodwill in acquisitions of entities whose dominant business is the ownership and operation of oil and gas or mineral properties. In the absence of other substantial business activities, the staff presumes that substantially all the value of the acquired entity not otherwise accounted for by tangible and identifiable intangible assets is derived from the value of the mineral or oil and gas reserves owned by that entity. In these business combinations, the purchase price ordinarily should be allocated entirely to the properties and other net tangible and identifiable intangible assets acquired, with no allocation to goodwill. However, if an excess purchase price is clearly indicated by all reasonable valuations of the oil and gas or mineral properties and other net tangible and intangible assets, recognition of goodwill would be appropriate. Also, the staff does not view recognition of goodwill as inconsistent with business combinations involving entities that have substantial activities outside of owning and operating oil and gas or mineral properties.

> 5. APPLICABILITY OF SFAS 121

Registrants that use the successful efforts method of accounting for oil and gas producing activities are required to assess impairment of proved properties using SFAS 121. The promulgation of SFAS 121 did not supersede the guidance in paragraph 28 of SFAS 19 on how to assess unproved properties for impairment.

Paragraph 25 of SFAS 121, which amends SFAS 19, states that its guidance applies only to proved properties and the costs of the enterprise's wells and equipment and facilities. Future net cash flows from unproved properties should not be grouped with future net cash flows from proved properties for purposes of evaluating proved properties or other related equipment and facilities for impairment.

If a registrant chooses to adopt a policy of evaluating unproved properties for impairment using future net cash flows, i.e., a methodology consistent with SFAS 121, it should consider paragraph 9 of SFAS 121. That paragraph requires a registrant to consider the likelihood of possible outcomes in determining the best estimate of future cash flows. The less objectively verifiable the source of the cash flows, the more likely those cash flows will not be fully realized.

If future net cash flows are used to evaluate unproved properties for impairment, registrants should risk adjust any unproved (sometimes referred to as probable or possible) reserves before estimating future cash flows associated with those resources. A "shortcut" method whereby a discount factor is applied only after calculating net cash flows derived from 100% of unproved reserves may materially overstate cash flows associated with properties where recovery costs currently exceed cash inflows. In addition, registrants should identify the categories of reserves included in assessing impairment of unproved properties, and the extent to which they are risk adjusted, in the notes to the financial statements.

> 6. CHANGES TO RATES DEPRECIATION, DEPLETION AND AMORTIZATION

Capitalized acquisition costs of proved properties must be amortized by the unit of production method so that each unit produced is assigned a pro rata portion of the unamortized cost. Paragraph 30 of SFAS 19 specifies that the unit cost must be computed on the basis of the total estimated units of proved oil and gas reserves. Amortization rates must be revised at least once a year, but also should be adjusted more often if there is an indication that total estimated units is materially different than previously estimated. Changes in amortization rates are required to be made prospectively as changes in estimates under paragraphs 31-33 of APB 20, and may not be effected as cumulative adjustments as if the rate were applicable in a period prior to the change in total estimated units.

Reserves quantities that are used to compute DD&A are frequently revised at a company's fiscal year end. When proved reserve estimates are revised prior to the release of operating results for a quarter, the staff will not object to the reserve revisions being implemented in the registrant's DD&A as of the beginning of that quarter, rather than delaying implementation until the following quarter. However, taking the reserve revisions back to earlier quarters is not appropriate.

> 7. FULL-COST ACCOUNTING

Costs associated with unevaluated properties may be excluded from costs tested for recoverability using the ceiling test specified in Rule 4-10(c)(4) of Regulation S-X. Unevaluated properties are synonymous with unproved properties as defined in paragraph 11a.1 of SFAS 19: "properties with no proved reserves." Costs associated with unevaluated or untested sites on proved properties may not be excluded from the ceiling test.
Companies using the full cost method should look to Rule 4-10(c)(6)(iii) and (iv) of Regulation S-X with respect to accounting for management fees and other income received for contractual services performed (e.g., drilling, well service, or equipment supply services, etc.) in connection with any property in which the registrant or an affiliate holds an ownership or other economic interest. Part (iv) does not distinguish between proved producing properties and unproved properties; the prohibition on income recognition applies to all properties. The rule's general prohibition of income recognition reflected the Commission's view that current recognition of income for services rendered in connection with an owned property would be inconsistent with the full cost concept under which income is recognized only as reserves are produced. The Commission indicated that income should be recognized only to the extent it exceeds a company's costs in connection with the contract and the properties, except for the limited circumstances described in Regulation S-X, Rule 4-10(c)(6)(iii)(B) and Rule 4-10(c)(6)(iv)(A) and (B). Accordingly, registrants must treat management and service fees as a reimbursement of costs, offsetting the costs incurred to provide the services, with any excess of fees over costs credited to the full cost pool and recognized through lower cost amortization only as production occurs.

> 8. CASH FLOWS STATEMENTS

Disbursements for remediation. Companies in extractive industries generally accrue the estimated costs of abandonment and remediation at the end of an asset's life over the useful life of the asset, as discussed in SAB Topic 5:Y:8. Subsequent cash disbursements reduce the accrued liability. Companies should present disbursements for accrued exit costs as operating cash flows in the statement of cash flows. It is not appropriate to present them as investing cash outflows.
Exploratory disbursements by successful efforts companies. Companies applying the successful efforts method of accounting for oil and gas producing activities capitalize costs only as allowed by SFAS 19. The costs of exploratory wells are initially capitalized, but may remain capitalized only if proved reserves are found within a year of capitalization. Cash expenditures for exploratory wells are appropriately classified within "investing activities" in the cash flows statements. SFAS 19 specifies in paragraph 13 that certain costs of oil and gas producing activities, such as geological and geophysical costs, do not result in the acquisition of an asset and should be charged to expense. Cash expenditures for these costs should not be classified as investing activities in the statement of cash flows.

> 9. HEDGING TRANSACTIONS

The FASB indicated in Statement No. 69 that the standardized measure of discounted net cash flows relating to oil and gas reserves is based on characteristics of a fair market value measure of the enterprise's reserves standardized to ensure comparability and objectivity. Paragraph 30 specifies that the standardized measure must be based on year-end prices relating to the proved reserves. In the absence of year-end contractual arrangements that are specific to a property, the year-end market price should be used. Effects of hedging transactions may be provided supplementally to the standardized measure disclosures. Registrants should also consider the requirements of Items 303 and 305 of Regulation S-K with respect to hedging activities and investments in commodity derivatives.

> 10. EXPLORATION STAGE (DEVELOPMENT STAGE) MINING COMPANIES

Instructions to paragraph (a) of Industry Guide 7 state that "Mining companies in the exploration stage should not refer to themselves as development stage companies in the financial statements, even though such companies should comply with FASB Statement 7, if applicable." As a result, financial statement headnotes and footnotes for exploration stage companies should describe the companies as being in the "exploration stage," rather than development stage. This is because the term development stage as defined in Industry Guide 7 applies only to companies with established commercially minable deposits (reserves) for extraction, which are not in the production stage.

G. Accounting and Disclosure for Rollups of Businesses (SAB 97)

On July 31, 1996, the staff issued Staff Accounting Bulletin ("SAB") 97 setting forth its views regarding two issues involving purchase business combinations: (a) the application of SAB 48, "Transfer of Nonmonetary Assets by Promoters or Shareholders," to purchase business combinations consummated and (b) the identification of an accounting acquirer in purchase business combinations.

The SAB states that SAB 48 was not intended to modify the requirements of Accounting Principles Board Opinion Number 16, Business Combinations (APB 16). If a business combination fails to meet the conditions specified by APB 16 for the pooling-of-interests method of accounting, it should be accounted for using the purchase method. Under the purchase method, the acquiring company allocates the cost of the acquired company to the individual assets acquired and liabilities assumed based on their fair values, rather than using their historical cost ("promoter's cost") as is prescribed by SAB 48 for certain exchanges of stock for nonmonetary assets. The clarification regarding the application of SAB 48 to business combinations is applicable to all merger agreements entered into after the issuance of the SAB.

> 1. IDENTIFICATION OF AN ACCOUNTING ACQUIRER

The SAB expresses the staff's view that an acquiring entity must be identified in any business combination that does not meet the conditions specified in APB 16 for application of the pooling of interests method. If no single former shareholder group of the combining companies obtains more than 50% of the outstanding stock of the new combined entity, the staff believes that the shareholder group receiving the largest ownership interest in the new combined entity should be presumed to be the accounting acquirer unless objective and verifiable evidence rebuts that presumption and supports the identification of a different shareholder group as the acquirer for accounting purposes.

If a new corporation is formed to issue shares in a combination, paragraph 71 of APB 16 states that one of the existing corporations, rather than the new corporation, should be considered the acquirer. That guidance, which does not contemplate that the newly formed entity may have substance apart from either of the combining entities, may not apply to certain SAB 97 transactions where a Newco is formed primarily by a group of investors separate from any of the operating companies. If such an independently formed Newco receives the largest voting interest, and/or controls the board or management, the Newco may be the acquirer.

> 2. ACCOUNTING FOR SHARES ISSUED TO FOUNDERS OF NEWCO

The treatment of the shares received by the shareholders of an independently formed Newco depends on whether the Newco is the acquirer or the target.

If the Newco is the accounting acquirer, shares issued to founders by the Newco (or received in exchange for shares of the legal acquirer) may be a form of compensation for services rendered or to be rendered. The proximity of the issuance to the IPO and the status of any agreements with the combining companies will affect the value of such shares.

If the Newco is deemed to be acquired by one of the operating companies, the value of the shares issued to the founders should be allocated to one, or a combination, of the following: acquisition costs (goodwill); compensation (expense for the period); or offering costs of the IPO (offset against offering proceeds).

> 3. VALUATION OF SHARES ISSUED IN THE COMBINATION

The shares issued in the roll-up of several businesses have been recorded in some cases at a substantial discount to the offering price. The staff has taken the position that the offering price is the best estimate of fair value. Any discount from that value must be justified by the application of a rational objective method.

Discounts have been attributed to the transfer restrictions under Rule 144, other contractual restrictions, and the existence (or lack of) piggy-back and other registration rights. As general guidance, the staff believes that Rule 144 may account for a nominal discount, and any greater discount requires objective evidence specifically relevant to the registrant's particular facts and circumstances. The proximity of issuance to the offering (if some issuances are prior to the IPO), the nature and length of any resale restrictions and the existence (or lack) of registration rights, may impact the value of the shares.

> 4. FINANCIAL STATEMENT REQUIREMENTS

In addition to the financial statements of the registrant (Newco), footnote 3 to SAB 97 indicates that financial statements of the accounting acquirer should be provided in a registration statement for the periods specified in Rules 3-01 and of Regulation S-X, as well as each individually significant acquired company pursuant to the requirements of Rule 3-05 of Regulation S-X and SAB 80. Financial statements of the accounting acquirer should not be presented on a basis combined with the pre-acquisition financial statements of the acquired companies, except to the extent prescribed by Article 11 of Regulation S-X ("Pro Forma Financial Statements"). The significance of acquired entities under Rule 3-05 should be measured against the accounting acquirer, which may be the registrant (Newco). In most cases, the financial statements of each acquired company will be required.

In subsequent filings under the Exchange Act, continued presentation of the financial statements of the registrant and the accounting acquirer (through the earlier of the date of acquisition or balance sheet date) is required. If a predecessor company (other than the accounting acquirer) can be identified, financial statements of the predecessor (through the earlier of the date of acquisition or balance sheet date) should also be provided. In Form 10-K, the financial statements of the accounting acquirer and the predecessor, if different, should be audited through the earlier of the date of acquisition or balance sheet date.

If a registrant makes another acquisition after the business combination, and the financial statements of the acquired company were not included in the registration statement, significance under Rule 3-05 of Regulation S-X should be measured against the registrant's (Newco's) audited financial statements for the most recent fiscal year. Upon written request the staff will consider whether relief from the literal application of Rule 3-05 is appropriate.

H. Reporting by Hotel Management Companies

Some hotel management companies have asserted that the agreements under which they manage hotel properties are, in substance, leases. As such, the arrangements are required to be accounted for pursuant to SFAS 13. Accounting for a contract that is in substance a lease is not elective; the staff would expect all entities entering into substantially identical contracts to account for them in an identical manner. The staff believes that determining whether a contract is a service agreement or a lease is dependent on the facts and circumstances, and requires a rigorous analysis of the rights, obligations, risks and rewards of the management company and the property owner. The staff's experience has been that management agreements generally do not convey the same rights and obligations as a lease agreement.

Other hotel management companies believe that the management agreement provides such extensive control over the property that its consolidation, or a reporting display similar to consolidation, is appropriate. The staff believes that guidance issued recently by the EITF (Issue No. 97-2) should be considered in determining the appropriate accounting and reporting for managed properties. Although that consensus addresses directly the consolidation of managed physician practices by the manager, hotel management companies should consider that guidance also to determine whether consolidation of the properties is required or permitted in their financial statements. Consolidation of managed hotels, or any similar manner of display, is appropriate only if the management company obtains a controlling financial interest in the managed property through a contractual service agreement. The criteria indicating a controlling financial interest are specified in EITF 97-2.

I. Credit Linked Securities of Bank Subsidiaries

Recently, a number of banks proposed the following transaction structure:

the bank forms a limited purpose finance subsidiary;
the bank transfers mortgages or asset-backed securities to the subsidiary;
the bank owns all of the subsidiary's common stock; and
the subsidiary registers the sale of its preferred stock to the public.

The source of funds for dividend payments on the preferred stock would be limited to the income generated by the finance subsidiary's assets. The banks proposed this structure because the preferred securities of the subsidiary may, under relevant risk based capital guidelines, qualify as capital of the bank.

Under bank regulations, if a financial regulatory event occurs, banks must retrieve or "claw back," the assets of these subsidiaries. Because the assets of these subsidiaries are subject to this claw back, this structure raises significant registration and disclosure issues.

Under one structure, the preferred securities of the subsidiary automatically convert into securities of the bank. Therefore:

the bank and the subsidiary must be co-registrants on the registration statement for the initial sale of the preferred stock since the bank is also offering preferred stock;
the full audited financial statements of the bank must be included in this registration statement; and
if the bank's financial statements are not in U.S. GAAP, they must be reconciled to U.S. GAAP.

If the bank regulators can require the bank to claw back the subsidiary's assets, the financial condition of the bank is material to the subsidiary preferred stockholder at all times. Therefore:

the full audited financial statements of the bank must be in the registration statement and in the subsequent periodic reports of the subsidiary; and
if the bank's financial statements are not in U.S. GAAP, they must be reconciled to U.S. GAAP.

J. Disclosures about Foreign Operations and Foreign Currency Transactions

An increasing number of registrants conduct material operations outside their home country and enter into material transactions denominated in currencies other than the currency in which their financial statements are reported. These registrants should review management's discussion and analysis and the notes to financial statements to ensure that disclosures are sufficient to inform investors of the nature and extent of the currency risks to which the registrant is exposed and to explain the effects of changes in exchange rates on its financial statements.

SFAS 131 requires quantitative disclosures about foreign operations. Geographic areas presented should be meaningfully disaggregated to portray disparate risks and operations. SFAS 131 requires separate disclosure of information about foreign operations and domestic operations. As domestic and foreign operations are required to be segregated, it is not appropriate for a U.S. company to present a North American segment that combines Canadian/Mexican operations with the U.S. Also, MD&A should describe any material effects of changes in currency exchange rates on reported revenues, costs, and business practices and plans. Registrants should quantify the extent to which material trends in amounts are attributable to changes in the value of the reporting currency relative to the functional currency of the underlying operations; any materially different trends in operations or liquidity that would be apparent if reported in the functional currency should be analyzed.

Identification of the currencies of the environments in which material business operations are conducted should be made where exposures are material. Discussion of foreign operations in a disaggregated manner may be necessary, particularly with respect to businesses operating in highly inflationary environments or if operating cash flows of a foreign operation are not available for legal, tax or economic reasons to meet the registrant's other short term cash requirements. Registrants should identify material unhedged monetary assets, liabilities or commitments denominated in currencies other than the operation's functional currency, and strategies for management of currency risk should be described.

K. Industry Guide 3 — Banks and Similar Lending Businesses

The staff expects to propose changes to Industry Guide 3 to reflect changes in accounting for investments and loans resulting from the adoption of SFAS 114, 115, 118 and other standards. In the interim, the staff has advised registrants to consider the following in the preparation of statistical and other data pursuant to the Industry Guide.

> LOAN YIELD AND RATIO INFORMATION

For purposes of disclosing yield information about investments available for sale, the staff has requested that registrants compute average yield using the historical cost balances, with footnote disclosure that the yield information does not give effect to changes in fair value that are reflected as a component of stockholders' equity. However, for computation of ratios, such as return on assets and return on equity, the calculations should be based on recorded assets and liabilities, giving effect to effects of changes in market value of available for sale securities.

>> Loan impairment and allowance policies

Disclosures about risk elements and impaired loans should reflect the particular methodology established for certain loans pursuant to SFAS 114 and 118. The table of impaired loans should disclose the carrying value by type of loan, broken out into groups based on how such loans were measured (e.g., present value of expected cash flows; fair value of collateral; observable market price). The components of the end of period allowance for loan losses should distinguish the portion attributable to loans accounted for pursuant to SFAS 114. Disclosure in the filing should explain fully how management determines when a loan is impaired and when a loan is written off. Significant policies followed regarding payment delinquency periods and methods of recognizing interest income and cash receipts on impaired loans should be disclosed.

>> Concentrations of Commitments and Loans

Known uncertainties relating to a significant concentration of commitments or loans, such as commercial real estate loans, in areas experiencing deteriorating financial conditions may be required to be disclosed by bank and thrift holding companies and insurance companies.

Guide 3 ("Loan Concentrations") requires disclosure of any concentration of loans exceeding 10% of total loans and Item 303 of Regulation S-K (MD&A) requires disclosure of any known trends and uncertainties reasonably likely to impact future operations (e.g., concentrations of higher risk assets or commitments that are significant in relation to shareholder equity but which may be less than 10% of total loans). Registrants should consider whether such uncertainties are reasonably likely to materially impact future operations so as to require disclosure under MD&A even though such concentration of loans otherwise may not meet the threshold for disclosure under Industry Guide 3.

If disclosure is required by either or both of these items, such disclosure should address matters such as the geographic areas involved, the related amounts of loans, commitments, or other real estate held, the potential risks inherent in such holdings, any recent material adverse trends in loan performance in such areas, including the amounts of such loans on a nonaccrual status or otherwise considered to be nonperforming, a description of the deteriorating economic conditions including known information as to vacancy rates and real estate values, relevant lending and risk management policies (e.g., extent collateralized; whether, when, and the extent real estate appraisals are updated and/or are reflective of current market conditions), and the extent the company continues to treat any such loans outstanding as fully performing when known credit problems raise serious doubts that the borrowers can continue to comply with present repayment terms. See Item 303 of Regulation S-K, Item III.C.2. ("Potential Problem Loans") of Industry Guide 3, and the interim period updating requirements of General Instruction 3(d) to such Guide.

L. Industry Guide 6 — Property Casualty Reinsurance Disclosures

SEC Industry Guide 6 provides disclosure guidance for registrants with material property casualty insurance operations. That Guide calls for tabular information depicting the activity with respect to loss reserve estimates and revisions to those estimates over time. Statement of Financial Accounting Standards No. 113 (SFAS 113) changed the long-standing practice of reporting loss reserves net of related reinsurance benefits, and requires that loss reserves be reported gross in the financial statements with reinsurance recoverables separately reported as an asset. The staff has not objected to the continued presentation of Guide 6 tables on a basis that is net of reinsurance, notwithstanding SFAS 113. However, for periods in which the income recognition provisions of SFAS 113 have been applied, the staff believes that additional quantitative and narrative disclosure is necessary to fully inform investors regarding the effects of a registrant's reinsurance programs.

At a minimum, the staff believes additional data should be provided that (a) reconciles the net end-of-period liability (the original reserve estimate in the 10 year loss development table) with the related gross liability on the balance sheet, and (b) presents the gross re-estimated liability as of the end of the latest re-estimation period, with separate disclosure of the related re-estimated reinsurance recoverable.

Guide 6 calls for a discussion of reinsurance transactions that have a material effect on earnings or reserves. The staff would expect that the additional data outlined above, and the disclosures of ceded losses specified by paragraph 16 of SFAS 113, will be used as a basis for discussion of the effects of a registrant's reinsurance programs. The staff also would expect a registrant to explain changes in patterns of net loss recognition resulting from the application of SFAS 113. Material historical and expected effects of trends and uncertainties in loss reserves and reinsurance recoverables on registrants' results of operations, liquidity and capital resources also should be disclosed in MD&A.