. 2
( 3)


sure management™s pro¬ciency in discovering reserves. Texaco™s 1999 ¬nding cost was
$4.37 per BOE,11 well above both the carrying cost of reserves and the ¬nding costs over the
¬ve-year period ending in 1999. Finding costs can be compared by geographic area and over
time, although we have not done so here.

Disclosure of Present Value Data
Table II, “Standardized Measure,” reports the estimated future cash ¬‚ows of the speci¬c re-
serves owned by the ¬rm. The following elements are presented:

1. Future cash in¬‚ows. Based on a year-by-year schedule of planned unit production,
multiplied by current price levels, that is, future gross revenues based on current
prices. Companies are not permitted to assume price changes, unless provided for by
a ¬rm contract, which may then be incorporated in the computation. These calcula-
tions use proved developed reserves only.
2. Future production costs. Also based on current prices. Production costs include all
expenditures required to bring the oil or gas to market.

Reported in Table V of Texaco™s 1999 Supplemental Oil and Gas Information.

3. Future development costs. Include the cost at current price levels of additional wells
and other production facilities that may be required to produce the reserves.
4. Future income tax expense. The estimated tax liabilities assuming that the forecast
cash ¬‚ows actually take place.
The net of these amounts, net future cash ¬‚ows before discount, is a forecast of net cash
¬‚ows from existing oil and gas reserves. These data must also be adjusted to re¬‚ect the time
value of money by discounting to present value. SFAS 69 requires that all ¬rms use a dis-
count rate of 10%. The objective is comparability; the “correct” discount rate will vary over
time and, perhaps, from ¬rm to ¬rm.
The result is a net present value of the after-tax12 cash ¬‚ows expected from the ¬rm™s re-
serves. Note that these data are provided separately for reserves in different geographic
areas, but with oil and gas combined.
Companies providing these data routinely state that the standardized measure is not market
value and suggest that the data have limited usefulness. Nonetheless, the data are widely used
in the analysis of companies with oil and gas reserves and, in practice, are a useful approxima-
tion of market value. Despite some limitations, the data are far more representative of market
values than the cost shown on the balance sheet, regardless of the accounting method used.13

Using Present Value Disclosures
How can the data be used? One simple adjustment is to replace the capitalized cost of re-
serves with the net present value (standardized measure). This is one step in preparing a cur-
rent value balance sheet (see Chapter 17) or computing adjusted net worth. Before making
this adjustment, the following issues should be considered:
1. Have prices changed since the balance sheet date? If so, the present value data must
be adjusted to current prices, for example, a 10% increase in oil prices increases fu-
ture cash ¬‚ows by 10%. (Because oil and gas prices do not always move together,
use a weighted-average based on the composition of reserves.)
2. Costs may also be adjusted. Although hard data are dif¬cult to come by, industry
sources can provide a rough guide as to changes in production and development costs.
3. Do economic or other factors suggest a need for assumptions of future price
changes? Some analysts construct their own price scenarios and make their own
computations of future cash ¬‚ows.
4. Is 10% the right discount rate? The discount rate is a function of the general level of
interest rates and the relative riskiness of the ¬rm™s reserves. Adjustments may be re-
quired. A higher discount rate, of course, reduces the net present value calculation; a
lower rate increases the present value.
5. Should pretax or after-tax net present values be used? The answer depends on the tax
status of the ¬rm and purpose of the analysis.14 In a liquidation analysis, for example,

Texaco deducts tax payments from net cash ¬‚ows (both undiscounted) and then discounts the after-tax cash ¬‚ows.
We can estimate the discounted income taxes by using the ratio of the discounted pretax cash ¬‚ows to the undis-
counted cash ¬‚ows. (This assumes a constant tax rate.)
Some ¬rms deduct the present value of tax payments from the net present value of pretax cash ¬‚ows. The re-
sult is the same, but this latter case permits more accurate calculation of the pretax net present value.
Surprisingly, early empirical studies did not seem to bear this out. Harris and Ohlson (1987) and Shaw and Wier
(1993), for example, found that SFAS 69 disclosures had weak explanatory power for stock prices and that book value
measures outperformed the standardized present value measure. More recently, however, Boone (2002) demonstrated
that the valuation models used in the previous studies were misspeci¬ed and, for the valuation model used in his
study, the present value measure exhibited signi¬cantly more explanatory power than the historical cost measure.
Disclosures for ¬rms with signi¬cant reserves outside of North America and Europe frequently show very high income
tax rates for these reserves. These high rates re¬‚ect the fact that royalties in many countries are a percentage of the gross
value of the oil or gas produced. Accounting for these royalties as income taxes obtained better income tax treatment in
the United States. This suggests that net present value data for such reserves should always be used on an after-tax basis.
Texaco™s “Other East” clearly ¬ts the category just described, with an estimated tax rate of 64% in 1999
[$7,665/($7,665 $4,323)].

when all cash ¬‚ows are evaluated on a pretax basis, pretax present values would be
used for consistency.

Example: Texaco
To illustrate, we use the data provided by Texaco and the following assumptions:
1. No change in prices or costs
2. A 10% discount rate
3. Pretax net present values for U.S. reserves but after-tax present values for foreign re-
serves.15 The data provided can be used to adjust Texaco™s equity at December 31,
1998 and 1999, for the difference between the present value of its oil and gas re-
serves and the carrying amount:

Years Ended December 31

Standardized Measure 1998 1999
United States* $ 4,879 $15,604
Europe 1,382 4,990
Other areas** $ (1,116 $23,909
Total $ 9,375 $26,502
Carrying amount $12,190 $13,038
Excess $ (2,815) $13,464
Reported equity $11,833 $12,042
Adjusted equity $ 9,018 $25,506
% change 24% 112%
Total debt $ 7,291 $ 7,647
Debt-to-equity ratio
Reported 0.62 0.64
Adjusted 0.81 0.30
*Using United States 1999 as an example, $15,604 was calculated as
the net present value ($11,352) plus the estimated present value of in-
come tax payments ($4,252). The later is estimated by applying the
ratio, ($11,352/$22,168) ($8,304) and assuming a constant rate.
**Sum of Other West, Other East, and Af¬liate (after-tax) present values.

This adjustment more than doubles Texaco™s equity at December 31, 1999; for 1998
the adjustment reduces equity by 24% because of low oil and gas prices on that date. The
adjustment sharply reduces Texaco™s debt-to-equity ratio in 1999. Varying the discount
rate or making assumptions about changes in prices or costs would also lead to different
The adjustment of net worth is not an end in itself, but one step in the analysis of a ¬rm.
Although equity after adjustment is not a precise measure of the market value of Texaco™s
net assets, it is a better measure than the historical cost of those assets. Chapter 17 discusses
the usefulness of equity adjustments in greater detail.

Adjustments for Subsequent Price Changes
In 2000, natural gas prices rose sharply from the year-end 1999 levels. As a result the De-
cember 31, 1999 present value data no longer re¬‚ected the economic value of Texaco™s re-
serves. Exhibit 7B-1 shows the assumptions and calculations required to adjust the 1999
standardized value of U.S. reserves for subsequent price changes.

See footnote 14.

Adjustments to Present Values for Subsequent Price Changes
Amounts in $ millions except for reserve quantities (oil in millions of barrels, gas in billions of
cubic feet)

A. Future Cash In¬‚ows

Quantity Unit Price Cash Flows

December 31, 1999
Crude oil and natural gas liquids 1,361 $25.60 $34,842
Natural gas 3,388 2.33 $47,894
December 31, 2000 Estimated

Crude oil and natural gas liquids 1,361 $26.80 $36,475
Natural gas 3,388 9.77 $33,101
B. Standardized Measure

Reported Adjusted Explanation

Future cash in¬‚ows $ 45,281 $ 69,576 Part A
Future production costs (10,956) (12,052) 20% higher
Future development costs $1(3,853) $1(4,238) 20% higher
Pretax net cash ¬‚ow $ 30,472 $ 53,286
Future income tax expense $1(8,304) $(14,521) Same rate
Net future cash ¬‚ows $ 22,168 $ 38,765
Discount (10% rate) $(10,816) $(18,914) Same rate
Standardized measure $ 11,352 $ 19,851

C. Discussion

The objective is to recompute the standardized measure using price changes at a later period. In part A,
we estimate the future cash ¬‚ows associated with Texaco™s U.S. reserves, using reserve quantities from
Table I of the 1999 supplementary data and prices obtained from the futures market at December 31,
1999. Our computed future cash ¬‚ows of $42.7 billion is nearly 6% below the $45.3 billion shown in
Table II. The difference must be due to different prices as the standardized measure must use proved
We estimate future cash ¬‚ows at December 31, 2000 using the same reserve quantities but with
prices at December 31, 2000. These calculations produce future cash ¬‚ows of $69.6 billion, 63% higher
than the December 31, 1999 level.
In part B, we adjust each component of the standardized measure to estimated levels at December
31, 2000. The future cash in¬‚ows come from part A. We assume 20% increases in both future produc-
tion costs and future development costs, on the assumption that the cost of drilling equipment and ser-
vices rises with higher oil and gas prices. We assume the same tax rate (27.25%). We also assume the
same production time pattern so that the % discount is unchanged. These calculations produce a 75%
increase in the standardized measure for U.S. oil and gas reserves, to $19.8 billion. The actual standard-
ized value (see Exhibit 7BP-1) at December 31, 2000 was just under $18 billion. The major reason for
the difference was that reserves declined during 2000, reducing future cash ¬‚ows to the following

December 31, 2000 Actual Quantity Unit Price Cash Flows

Crude oil and natural gas liquids 1,202 $ 26.80 $ 32,214
Natural gas 3,299 9.77 $332,231
$ 64,445

Lower reserves reduces future cash ¬‚ows and, therefore, lowers the standardized value.

Changes in Present Values
Table III is a reconciliation of changes in the standardized measure, akin to the reconcili-
ation of reserve quantities. But these data are richer as they include the impact of such
factors as:
• Changes in prices and costs
• Accretion of discount (the passage of time reduces the discount period)
• Expenditures that reduce future required cash ¬‚ows
• Changes in estimates
• Purchases and sales of reserves
• Effect of production

The standardized measure of Texaco™s oil and gas reserves declined by nearly one-third in
1997 and more than half in 1998, but soared to a higher level at December 31, 1999. The rec-
onciliation provides the following insights:
1. Changing prices and costs were the major factor accounting for the sharp decline in
the standardized measure in 1997 and 1998 and its recovery in 1999.
Over the three-year period, the price effect was slightly negative.
2. Texaco™s quantity revisions were positive each year, suggesting that the company™s
estimates have been conservative.
3. Timing effects were negative each year, suggesting that Texaco™s production rate
was below previous forecasts.16

Summary and Conclusion While the supplemental oil and gas data mandated by
SFAS 69 must be used with care, they provide considerable useful information regarding
the firm™s exploratory activities and the value of its reserves. These data are far more
comparable among firms than reported financial data as most are unaffected by account-
ing methods.

7B-1. [Changes between full cost and successful efforts methods] Sonat [SNT], a diversi¬ed
energy company, announced the following accounting change when it reported its re-
sults for the third quarter of 1998:
Sonat Exploration Company [Sonat subsidiary] changed from successful efforts to full cost
accounting because its future capital spending will be focused signi¬cantly more on explo-
ration activity than in the past. Full cost accounting, which amortizes rather than expenses
dry-hole exploration and other related costs, provides a more appropriate method of match-
ing revenues and expenses. Exploration activity has increased from 6 percent of 1995 capi-
tal spending, or $27 million, to an estimated 33 percent of 1998 capital spending, or
approximately $175 million. . . .
The adoption of the full cost method is expected to increase 1998 and 1999 normalized
earnings from levels that would have been reported under successful efforts accounting and,
more important, will reduce earnings volatility from quarter-to-quarter and year-to-year
going forward. . . . The change to full cost accounting will not materially affect the com-
pany™s cash ¬‚ow from operations.
Sonat has restated all prior period statements . . . all previous charges related to the
impairment of Sonat Exploration™s assets . . . were reversed, which significantly raised
the book value of those properties as well as Sonat™s stockholders™ equity. The full cost
method, however, requires quarterly ceiling tests17 to insure that the carrying value of as-
sets on the balance sheet is not overstated. . . . The end result of the full cost conversion

Postponing production reduces the net present value by increasing the discount factor.
Authors™ note: see footnote 3 to this appendix and the related text.

is that both the book value of Sonat Exploration™s properties and Sonat™s stockholders™
equity are at higher levels than if it had continued with the successful efforts method of

Note 2 to Sonat™s annual report for the year ended December 31, 1998 reports the fol-
lowing effects of the accounting change and restatement of prior periods:

Effect on 1996 1997 1998

Net income ($thousands) 18,006 130,584 (258,351)
Earnings per share, fully diluted .16 1.17 (2.35)

The 1998 income statement reports ceiling test charges of $1,035,178 thousand. Re-
tained earnings at January 1, 1996 were increased by $199,196 thousand for the ac-
counting change.
A. Explain each of the following bene¬ts from the accounting change stated in the
Sonat press release:
(i) Increased normalized earnings
(ii) Reduced earnings volatility
(iii) Higher book value of exploration properties
(iv) Higher stockholders™ equity
B. Compute the effect of the accounting change on Sonat™s stockholders™ equity at
December 31, 1998.
C. Describe the effect of the accounting change on each of the following Sonat ratios
for 1998:
(i) Debt-to-equity ratio
(ii) Asset turnover
(iii) Book value per share
D. Explain why the accounting change was not expected to materially affect Sonat™s
cash from operations.
E. Given your answers to parts A through D, evaluate Sonat™s decision to change ac-
counting method.
F. The accounting change took place during a period of declining energy prices. De-
scribe the risk of making the accounting change and illustrate that risk using the
data provided.
G. Sonat had changed from the full cost method to successful efforts in 1991, a pre-
vious period of energy price declines. Describe the effect of that fact on your view
of the 1998 accounting change.
7B-2. [Analysis of Supplementary Oil and Gas Data] Exhibit 7BP-1 contains the supple-
mental oil and gas data from Texaco™s 2000 annual report. Use this exhibit, and the
data for 1999 and prior years from Texaco™s 1999 annual report, to answer the follow-
ing questions.
A. Compute Texaco™s reserve lives in years for 2000, for both oil and gas:
(i) In the United States
(ii) Worldwide
B. Discuss whether production trends mirror the reserve trends over the four years
ended December 31, 2000.
C. Compute Texaco™s capitalized cost per BOE for 2000:
(i) In the United States
(ii) Worldwide

Sonat press release, October 22, 1998.

Supplemental Oil And Gas Information

Note: These disclosures omit text and tables that duplicate the 1999 disclosures.
Table I”Net Proved Reserves
Net Proved Reserves of Crude Oil and Natural Gas Liquids (millions of barrels)

Consolidated Subsidiaries Equity

Af¬liate Af¬liate
United Other Other ”Other ”Other World-
States West Europe East Total West East Total wide

As of December 31, 1999* 1,782 55 427 670 2,934 ” 546 546 3,480
Discoveries & extensions 39 ” 21 9 69 374 ” 374 443
Improved recovery 25 ” ” 39 64 ” 14 14 78
Revisions (21) ” 9 30 18 ” 37 37 55
Net purchases (sales) (135) (52) (44) ” (231) ” ” ” (231)
Production (130) (3) (44) (78) (255) ” (52) (52) (307)

Total changes (222) (55) (58) ” (335) 374 (1) 373 38
Developed reserves 1,202 ” 219 559 1,980 ” 282 282 2,262
Undeveloped reserves 358 ” 150 111 619 374 263 637 1,256

As of December 31, 2000* 1,560 ” 369 670 2,599 374 545 919 3,518

*Includes net proved NGL reserves
As of December 31, 1998 250 ” 68 22 340 ” 6 6 346
As of December 31, 1999 250 ” 74 134 458 ” 1 1 459
As of December 31, 2000 219 ” 67 162 448 ” 1 1 449

Net Proved Reserves of Natural Gas (billions of cubic feet)

Consolidated Subsidiaries Equity

Af¬liate Af¬liate
United Other Other ”Other ”Other World-
States West Europe East Total West East Total wide

As of December 31, 1999 4,205 941 962 1,866 7,974 ” 134 134 8,108
Discoveries & extensions 585 ” ” ” 585 33 4 37 622
Improved recovery 5 ” ” ” 5 ” ” ” 5
Revisions 121 12 43 164 340 ” 8 8 348
Net purchases (sales) 8 (58) (11) ” (61) ” ” ” (61)
Production (494) (95) (81) (36) (706) ” (24) (24) (730)

Total changes 225 (141) (49) 128 163 33 (12) 21 184
Developed reserves 3,299 738 573 977 5,587 ” 121 121 5,708
Undeveloped reserves 1,131 62 340 1,017 2,550 33 1 34 2,584

As of December 31, 2000 4,430 800)
* 913 1,994 8,137)
* 33 122 155 8,292)

*Additionally, there are approximately 302 BCF of natural gas in Other West which will be available from production during the period 2005“2016 under
a long-term purchase associated with a service agreement.

EXHIBIT 7BP-1 (continued)

The following chart summarizes our experience in ¬nding new quantities of oil and gas to replace our production. Our reserve replace-
ment performance is calculated by dividing our reserve additions by our production. Our additions relate to new discoveries, existing re-
serve extensions, improved recoveries, and revisions to previous reserve estimates. The chart excludes oil and gas quantities from
purchases and sales.

Worldwide United States International

Year 2000 172% 76% 267%
Year 1999 111% 99% 124%
Year 1998 166% 144% 191%
3-year average 150% 109% 192%
5-year average 146% 108% 189%

Table II”Standardized Measure
Consolidated Subsidiaries

United Other Other
(Millions of Dollars) States West Europe East Total

As of December 31, 2000
Future cash in¬‚ows from sale of oil & gas,
and service fee revenue $ 67,115 $ 1,559 $ 10,549 $ 15,512 $ 94,735
Future production costs (13,107) (252) (2,074) (2,768) (18,201)
Future development costs (3,588) (30) (1,244) (1,280) (6,142)
Future income tax expense (17,024) (612) (2,238) (6,681) (26,555)

Net future cash ¬‚ows before discount 33,396 665 4,993 4,783 43,837
10% discount for timing of future cash ¬‚ows (15,407) (259) (1,778) (2,239) (19,683)

Standardized measure of
discounted future net cash ¬‚ows $ 17,989 $ 406 $ 3,215 $ 2,544 $ 24,154


Af¬liate Af¬liate
”Other ”Other World-
(Millions of Dollars) West East Total wide

As of December 31, 2000
Future cash in¬‚ows from sale of oil & gas,
and service fee revenue $ 3,917 $ 7,873 $ 11,790 $ 106,525
Future production costs (273) (2,853) (3,126) (21,327)
Future development costs (406) (694) (1,100) (7,242)
Future income tax expense (1,101) (2,189) (3,290) (29,845)

Net future cash ¬‚ows before discount 2,137 2,137 4,274 48,111
10% discount for timing of future cash ¬‚ows (1,431) (809) (2,240) (21,923)

Standardized measure of
discounted future net cash ¬‚ows $ 706 $ 1,328 $ 2,034 $ 26,188

EXHIBIT 7BP-1 (continued)

Table III”Changes in the Standardized Measure
Worldwide Including Equity in Af¬liates

(Millions of Dollars) 2000 1999 1998

Standardized measure beginning of year $ 18,710 $ 5,487 $ 12,057
Sales of minerals-in-place (3,990) (352) (160)

14,720 5,135 11,897

Changes in ongoing oil and gas operations:
Sales and transfers of produced oil and gas,
net of production costs during the period (7,345) (4,276) (3,129)
Net changes in prices, production, and development costs 11,389 22,036 (11,205)
Discoveries and extensions and improved recovery, less related costs 4,543 1,821 728
Development costs incurred during the period 2,043 1,598 1,770
Timing of production and other changes 670 (517) (1,170)
Revisions of previous quantity estimates 668 301 852
Purchases of minerals-in-place 901 895 48
Accretion of discount 3,120 881 1,916
Net change in discounted future income taxes (4,521) (9,164) 3,780

Standardized measure”end of year $ 26,188 $ 18,710 $ 5,487

Table IV”Capitalized Costs
Consolidated Subsidiaries Equity

Af¬liate Af¬liate
United Other Other ”Other ”Other World-
(Millions of Dollars) States West Europe East Total West* East Total wide

As of December 31, 2000
Proved properties $18,213 $137 $3,295 $3,699 $25,344 $ 66 $1,370 $1,436 $26,780
Unproved properties 1,026 98 58 655 1,837 68 265 333 2,170
Support equipment and facilities 257 81 28 135 501 42 906 948 1,449

Gross capitalized costs 19,496 316 3,381 4,489 27,682 176 2,541 2,717 30,399
Accumulated depreciation,
depletion, and amortization (12,084) (92) (1,821) (1,508) (15,505) (1) (1,349) (1,350) (16,855)

Net capitalized costs $ 7,412 $224 $1,560 $2,981 $12,177 $175 $1,192 $1,367 $13,544

*Existing costs were transferred from a consolidated subsidiary to an af¬liate at year-end 2000.

Table V”Costs Incurred
On a worldwide basis, in 2000 we spent $3.62 for each BOE we added. Finding and development costs averaged $3.74 for the three-
year period 1998“2000 and $3.92 per BOE for the ¬ve-year period 1996“2000.

Consolidated Subsidiaries Equity

Af¬liate Af¬liate
United Other Other ”Other ”Other World-
(Millions of Dollars) States West Europe East Total West East Total wide

For the year ended December 31, 2000
Proved property acquisition $ 138 $” $” $ 276 $ 414 $ ” $” $” $ 414
Unproved property acquisition 5 12 ” ” 17 ” ” ” 17
Exploration 227 62 18 287 594 ” 19 19 613
Development 716 121 334 677 1,848 ” 169 169 2,017

Total $1,086 $195 $352 $1,240 $2,873 $ ” $188 $188 $3,061

EXHIBIT 7BP-1 (continued)

Table VI”Unit Prices
Average sales prices are calculated using the gross revenues in Table VII. Average lifting costs equal production costs and the
depreciation, depletion, and amortization of support equipment and facilities, adjusted for inventory changes.

Average Sales Prices

Af¬liate Af¬liate
United Other Other ”Other ”Other
States West Europe East West East

Crude oil (per barrel)
2000 $26.20 $22.74 $26.86 $22.81 $ ” $21.52
1999 14.97 14.12 17.15 15.33 ” 13.24
1998 10.40 9.65 11.73 9.61 ” 9.81
Natural gas liquids (per barrel)
2000 18.73 ” 17.93 ” ” ”
1999 10.86 ” 12.53 ” ” ”
1998 8.99 ” 11.89 ” ” ”
Natural gas (per thousand cubic feet)
2000 3.67 1.13 2.49 1.23 ” ”
1999 2.07 .77 1.99 .18 ” ”
1998 1.93 .92 2.42 .38 ” ”

Average lifting costs (per barrel of oil equivalent)

Af¬liate Af¬liate
United Other Other ”Other ”Other
States West Europe East West East

2000 $5.05 $2.94 $5.08 $3.03 $ ” $5.06
1999 4.01 2.87 6.15 3.45 ” 3.95
1998 4.07 1.86 5.24 3.65 ” 2.68

Table VII”Results of Operations
Consolidated Subsidiaries

United Other Other
(Millions of Dollars) States West Europe East Total

For the year ended December 31, 2000
Gross revenues from:
Sales and transfers, including af¬liate sales $ 4,460 $” $ 869 $ 1,440 $ 6,769
Sales to unaf¬liated entities 545 190 591 315 1,641
Production costs (1,070) (46) (375) (232) (1,723)
Exploration costs (130) (62) (18) (152) (362)
Depreciation, depletion, and amortization (723) (18) (221) (147) (1,109)
Other expenses (190) (27) (2) (88) (307)

Results before estimated income taxes 2,892 37 844 1,136 4,909
Estimated income taxes (972) (48) (269) (945) (2,234)

Net results $ 1,920 $ (11) $ 575 $ 191 $ 2,675

EXHIBIT 7BP-1 (continued)


Af¬liate Af¬liate
”Other ”Other World-
(Millions of Dollars) West East Total wide

For the year ended December 31, 2000
Gross revenues from:
Sales and transfers, including
af¬liate sales $ ” $831 $831 $7,600
Sales to unaf¬liated entities ” 50 50 1,691
Production costs ” (223) (223) (1,946)
Exploration costs ” (14) (14) (376)
Depreciation, depletion,
and amortization ” (129) (129) (1,238)
Other expenses ” (2) (2) (309)

Results before estimated income taxes ” 513 513 5,422
Estimated income taxes ” (258) (258) (2,492)

Net results $ ” $255 $255 $2,930

Source: Texaco 2000 Annual Report

D. Discuss the trend, over 1998“2000, in Texaco™s capitalized cost per BOE, and ex-
plain how changes in reserve quantities and capitalized costs may have affected
that trend.
E. Review the data in Tables II and III and discuss the effect of each of the following
factors on the change in the standardized value over the four years ended Decem-
ber 31, 2000:
(i) Price changes
(ii) Revision of estimated reserve quantities
(iii) Income taxes
F. Discuss, based on your answers to part E, the extent to which Texaco replaced the
economic value of its reserves over the four years ended December 31, 2000.
G. Texaco™s reported debt at December 31, 2000 was $7,191 million with reported
equity of $13,444.
(i) Compute Texaco™s equity adjusted to replace the carrying cost of reserves
with the standardized value.
(ii) Compute Texaco™s debt-to-equity ratio using both reported and adjusted eq-
(iii) Discuss the effect of the adjustment on the trend of Texaco™s debt-to-equity
ratio over the period 1998 to 2000.
(iv) Describe the effect of the adjustment on Texaco™s asset turnover ratio.
H. The equity adjustment would appear to reduce Texaco™s return on equity.
(i) Discuss how you could adjust income, using the standardized measure, to
compute a current cost return on equity.
(ii) Explain how current cost ROE would be superior to reported ROE as a per-
formance measure.
(iii) Describe one drawback to using current cost ROE as a performance measure.
Appendix 8-A

1. Distinguish between general in¬‚ation and speci¬c price changes.
2. Describe and illustrate the constant dollar and current cost methods of adjustment for
changing prices.
3. Show how corporate disclosures can be used to adjust ¬nancial statements for the ef-
fects of price changes.
4. Show how corporate disclosures regarding capital expenditures can provoke ques-
tions intended to provide insights into corporate strategy.

Price changes have pervasive effects on ¬nancial statements, and good analysis must recog-
nize those effects and incorporate them into valuation decisions. Before discussing these is-
sues, it is important to distinguish between two types of price change: general in¬‚ation and
speci¬c price change.
General in¬‚ation refers to price changes for an economy as a whole. Indices such as the
consumer price index in the United States attempt to measure the impact of price changes on
the broad population. Speci¬c price changes refer to the prices of speci¬c goods and services
that are the inputs and outputs of ¬rms in a given industry.


From the ¬nancial analysis point of view, the impact of general in¬‚ation is that the purchas-
ing power of capital is continuously eroded. Analytically, there is a well-developed method
of dealing with this phenomenon, constant dollar accounting, also called general price level
accounting or purchasing power accounting.1 Its goal is to measure the impact of changes in
purchasing power (general in¬‚ation) on the ¬nancial capital of the ¬rm.
In the simple model depicted in Exhibit 8A-1, the ¬rm invests its capital in inventory at
the start of the ¬rst year and sells that inventory at the end of the year. At the beginning of
the next year, it again invests its capital (obtained from the sale of inventory one day earlier)
in inventory. For simplicity, we assume that there are no markups and no expenses other than
cost of goods sold.
The historical cost (or nominal dollar) model recognizes as income the difference between
the proceeds of sale and the cost of inventory for each year. The total income over the three-year
period is $331, the difference between beginning capital ($1,000) and ending capital ($1,331).

Accounting Principles Board (APB) Statement 4 (1969), Financial Statements Restated for General Price-Level



Assumptions: Capital at January 1, 2001, is $1000.
Each January 1, the ¬rm will invest entire capital in inventory.
Each December 31, the ¬rm will sell entire inventory.
Price of inventory is $100 per unit at January 1, 2001, and rises at 10% per annum.
The general price level (CPI-U) rises at 25% per annum. Base period is January 1,
2001 100.

Historical Cost Model
Cost of
Year Sales Goods Sold Income

2001 $1100 $1000 $ 100
2002 1210 1100 $(110
2003 1331 1210 $(121
Total $ 331

Constant Dollar Model
(January 1, 2001 dollars)
2001 880 1000 $(120)
2002 774 880 $(106)
2003 681 774 $1(93)
Total $(319)

Current Cost Model
2001 1100 1100 0
2002 1210 1210 $(000
2003 1331 1331 $(000
Total $0

CPI-U: January 1, 2001 100 December 31, 2001 125
January 1, 2002 125 December 31, 2002 156.25
January 1, 2003 156.25 December 31, 2003 195.31

This model, however, does not recognize the decline in the real value of money or ¬nan-
cial capital due to in¬‚ation. In this case, the purchasing power of $1,000 declines (at the rate
of 25%) to $800 ($1,000/1.25) in one year.

Constant Dollar Method
The constant dollar method recognizes this effect by restating all monetary amounts into
units of constant purchasing power at a designated base period, which can be any period of
time (all of 2001) or point in time (January 1, 2001). The base ¬xes the yardstick used to
measure purchasing power.
In our example, January 1, 2001 is the base so that all cash ¬‚ows will be restated into
units of January 1, 2001 purchasing power.
The nominal dollar cash ¬‚ow of $1,100 was received at December 31, 2001. In¬‚ation re-
duces the purchasing power of those dollars to only 80% (1/1.25) of the purchasing power at
the base date of January 1, 2001. Thus, we must divide the cash ¬‚ow by the relevant index
(1.25) to obtain revenues in January 1, 2001 dollars.
2001 Sales ($1/1/01) $880

Cost of goods sold (COGS) resulted from a cash out¬‚ow at January 1, 2001, and, there-
fore, requires no restatement. In constant dollar terms, therefore, net income for 2001 equals
2001 Income $880 $1,000 $(120)

In purchasing power terms, the ¬rm™s capital has declined. This results from the fact that
its inventory rose in price by less than the rate of in¬‚ation.
For 2002, we compute income in the same manner. The December 31, 2002 cash in¬‚ow
has lost purchasing power over a two-year period and the January 1, 2002 cash out¬‚ow must
be adjusted for one year™s in¬‚ation:
$1,210 $1,100
2002 Sales ($1/1/01) $774 COGS $880
1.5625 1.25
2002 Income ($1/1/01) $774 $880 $(106)

The calculations for 2003 are similar, resulting in
2003 Income ($1/1/01) $681 $774 $(93)

Over the three-year period, the constant dollar method reports a loss of $319 in purchas-
ing power of the ¬rm™s capital. At the end of 2003, the ¬rm has $1,331, the proceeds of in-
ventory sold at December 31, 2003. But in units of 1/1/01 purchasing power, the ¬rm™s
capital is only $681 ($1,331/1.9531), whereas its original capital was $1,000.
Note that these computations use the company™s actual cash ¬‚ows but the price index is
for the economy as a whole. The calculations do not take into account the speci¬c price
changes faced by the ¬rm. This feature of the constant dollar method is both its strength and
its weakness.

Advantages and Disadvantages of Constant Dollar Method
The constant dollar method involves very simple calculations and the erosion of purchasing
power is a simple economic concept. The method facilitates audits because it is objective as
the only choice involved is that of the in¬‚ation index, and given the same data, the results
will always be the same, contributing to ease of veri¬ability. For these reasons, corporate ¬-
nancial statement preparers and auditors have generally supported use of the constant dollar
method to disclose the impact of in¬‚ation.
From the standpoint of ¬nancial analysis, however, the constant dollar method has a sig-
ni¬cant drawback: Constant dollar data do not have any apparent usefulness. Although loss
of purchasing power is a useful economic concept, it has limited application in the ¬nancial
world. Stock prices, interest rates, and other ¬nancial data are stated in nominal currency
units, not real (purchasing power) units.


Contributing to the lack of utility of constant dollar data is their lack of speci¬city; they treat
all companies identically regardless of the composition of their assets and liabilities. For data
that relate to speci¬c companies, analysts prefer the current cost method.

Current Cost Method
The current cost2 method ignores general in¬‚ation in favor of the speci¬c price and cost
changes faced by the individual ¬rm. It starts with the idea that income, when properly mea-
sured, must include a provision for the replacement of capacity used during the period.3 Oth-
erwise, income is overstated as it includes the consumption of capacity.4

Current cost is the term used in SFAS 33 and other FASB standards. Previous accounting literature used such terms
as replacement cost, current value, and fair value. The distinction among these terms is often more theoretic than
real and varies with the user. For simplicity, we ignore these distinctions throughout the appendix.
J. R. Hicks, Value and Capital, 2nd ed. (Oxford: Chaundon Press, 1946), p. 176.
This concept was more fully developed in Chapter 2.

It follows that the provision for the cost of replacing capacity must be made at current
prices. Although application of this principle is dif¬cult in practice, it is essential in theory.
If a ¬rm has used up a machine and must replace it to remain in business, it is the cost of
buying the new machine that is relevant, not the original cost of the worn-out one.
The current cost method, therefore, measures income by matching revenues with operat-
ing costs, including the cost of replacing inventory sold and ¬xed assets used up during the
Exhibit 8A-1 applies this principle to our model company. At the end of 2001, the ¬rm
has $1,100 as proceeds of sales. To remain in business, the ¬rm must purchase new inven-
tory on January 1, 2002. The cost of that new inventory will be 1,100 (10 @ $110 per unit),
as prices have risen by 10% since January 1, 2001. Under the current cost method, therefore,
there was no income earned in 2001:
2001 Income $1,100 $1,100 0

The ¬rm can purchase 10 units of inventory, the same as its “capacity” one year earlier.
The ¬rm has neither a pro¬t nor a loss for 2001 but has simply maintained its physical capi-
tal (capacity to do business). This contrasts with the constant dollar method, which is con-
cerned with maintaining ¬nancial capital.
2002 and 2003 results are the same. There is no income in current cost terms because the
¬rm has simply maintained its physical capital.

Disadvantages of Current Cost
As compared with the constant dollar method, the current cost method is more complex: the
¬rm must estimate the cost to replace each type of inventory and each category of ¬xed as-
sets. We discuss the dif¬culty of estimating current costs shortly. These estimates require
judgements about how the ¬rm will replace used up capacity, adding subjectivity and a lack
of reliability to the results. Because of these factors, current cost data are more expensive and
time-consuming to prepare and audit than constant dollar data. For all these reasons, ¬nan-
cial statement preparers and auditors have mostly opposed the presentation of current cost
data in ¬nancial statements. In some cases, however, corporations have stated that they ¬nd
such data useful when managing their business.
For ¬nancial analysis, however, current cost data are greatly preferred to constant dollar
data. The main reason is the relevance of such data to the operations of speci¬c ¬rms.

Accounting Series Release 190
The high rate of in¬‚ation in the 1970s and large speci¬c price changes in some industries led
the Securities and Exchange Commission to issue Accounting Series Release (ASR) 190
(1976) requiring large ¬rms to disclose the replacement cost of inventory and ¬xed assets as
well as cost of goods sold and depreciation expense computed on a replacement cost basis.
Disclosures were ¬rst required in 1976.
At about the same time, the FASB placed in¬‚ation accounting on its agenda and issued
SFAS 33 in 1979, at which time the SEC withdrew ASR 190.

SFAS 33 Requirements
SFAS 33, Financial Reporting and Changing Prices, the ¬rst U.S. accounting standard to re-
quire disclosure of the impact of changing prices, was a hybrid; it attempted to combine both
the current cost and constant dollar methods into one standard. In theory, the two approaches
can be combined. Data adjusted for speci¬c price changes can then be further adjusted for
changes in purchasing power. The resulting complexity, however, made use of this data dif¬-
cult for ¬nancial analysts.
SFAS 33 provided for review after ¬ve years. SFAS 89 (1989) made the SFAS 33 dis-
closure requirements voluntary. This action resulted from three factors. First, the rate of in-
¬‚ation subsided greatly in the 1980s, making the issue of general in¬‚ation effects less
important. Second, preparers and auditors complained that the costs of compliance with

SFAS 33 were too high. Finally, little or no bene¬t could be traced to the disclosures. Be-
cause of the voluntary nature of SFAS 89, the disclosures are rarely provided.

Problems with SFAS 33 Disclosures
The data disclosed under the provisions of SFAS 33 received little use, we believe, for the
following reasons:
1. It was unclear whether companies should attempt to measure the market value, the
reproduction cost, or the replacement cost of existing capacity. Each of these choices
results in a different measure of cost and a different set of problems.
2. Market value is often dif¬cult to estimate because many productive assets are cus-
tomized or unique. Although market values can be estimated for of¬ce buildings, for
example, there is no active market for steel mills. Curiously, the FASB did not per-
mit the disclosure of market values in lieu of current cost for such assets as oil and
gas properties, timberland, and real estate, for which active markets do exist.5
3. Reproduction cost is an estimate of the cost to build existing facilities at current
prices. However, it is hard to price machines that are no longer being manufactured
(having been replaced by newer models or machines using different production
processes). Use of reproduction cost also assumes that the ¬rm would replace its ex-
isting capacity with exactly the same mix of factory sizes and locations.
Replacement cost is, in theory, the cost of replacing existing productive capacity. Such
an estimate must, ¬rst, de¬ne whether capacity should be measured in physical units (tons of
steel or pairs of shoes) or ¬nancial units (dollars of revenue). Second, the ¬rm must decide
what mix of geographic locations and plant capacities it would construct if it were to replace
its facilities today. Finally, the ¬rm must estimate what production processes, raw and inter-
mediate materials, and markets it would pursue if it could “start from scratch.”
The computations become increasingly speculative as one moves from the market value
of assets to reproduction cost to replacement cost. In many cases, companies complied with
SFAS 33 by simply applying construction and machinery cost indices to the historical cost of
¬xed assets.

Problems with Current Cost Depreciation
SFAS 33 also required that companies providing current cost data disclose depreciation ex-
pense on a current cost basis. At ¬rst glance, this is a simple exercise; companies simply
apply their existing depreciation methods and lives to their estimated current cost of ¬xed
The dif¬culties in de¬ning current cost carry over to the de¬nition of current cost depre-
ciation expense. In addition, the interpretation of current cost depreciation expense is subject
to another problem. Replacement of historical cost depreciation with current cost deprecia-
tion assumes that the operating costs of the ¬rm are unaffected by the “replacement” process.
It assumes that more expensive new machines and processes are no more cost ef¬cient than
the original machines and processes.
That assumption is, of course, absurd in most cases. In theory, therefore, the operating
costs of the ¬rm should be adjusted to re¬‚ect the greater ef¬ciency of the new equipment.
Such adjustments are subjective when made by the ¬rm; a ¬nancial analyst outside the ¬rm
cannot begin to make them.
Because of the subjectivity of the data, lack of comparability of disclosures by compet-
ing ¬rms, dif¬culty of interpreting the data, and lack of a well-de¬ned way of incorporating
the data into investment decision models, use of the current cost data provided by SFAS 33
was limited. Perhaps for that reason there is little evidence that current cost data impacted ¬-
nancial markets.

SFAS 39, Mining and Oil and Gas, SFAS 40, Timberlands, and SFAS 41, Income Producing Real Estate, were all
issued in 1980 as supplements to SFAS 33.

Adjusting Financial Statements for Changing Prices
Given the voluntary nature of changing prices disclosures under SFAS 89, the analysis of the
impact of changing prices must be done by each analyst. As we believe that constant dollar
calculations are of use only under limited circumstances (see the following section), we de-
vote our attention to adjustments for speci¬c price changes. As the effects of changing prices
on inventories are dealt with in Chapter 6, we concern ourselves here only with the effects on
¬xed assets.
Changing prices for ¬xed assets have two primary effects on ¬nancial statements:
1. Since ¬xed assets are carried at cost (net of accumulated depreciation), their carrying
amount does not re¬‚ect the current cost. Thus, the assets and the net worth are under-
stated if prices have risen (the normal case).
2. Depreciation expense is also understated because it is based on the understated carry-
ing amount of the ¬xed assets. Depreciation expense, which should be a measure of
the capacity used up during the period, is instead just an arbitrary allocation of past
cash ¬‚ows. Understatement of depreciation expense results in the overstatement of
reported earnings.

Adjustments to Fixed Assets
Some non-U.S. companies disclose asset values used for insurance or tax assessment purposes.

Example: Holmen
Footnote 10 of Holmen™s ¬nancial statements shows the assessed tax values of properties in
Sweden in 1998 and 1999. Exhibit 8A-2 shows how these data can be used to adjust tangible
assets and shareholders™ equity.
For each ¬xed asset category, we have computed the excess of tax values over carrying
values for the four years ended in 2000. This procedure underestimates the difference as the
tax values exclude properties outside of Sweden. Most of the excess relates to Holmen™s for-
est properties. If these properties had not been revalued in prior years, the cost (acquisition
value) of these properties would be a very misleading indicator of their worth.
The total excess value was SKr 6.3 billion at the end of 1997, but declined sharply in
1998. No explanation is provided, but we note that Modo Paper was spun off as a separate
company in 1998, removing its ¬xed assets from the analysis. In 1999, the excess value re-
lated to forest properties increased but the excess related to buildings declined. In 2000 there
was a small increase in the excess values.
Exhibit 8A-2 shows that adjustment for the excess of assessed tax values over carrying
value increases tangible assets by as much as 32.5% (1997) and stockholders™ equity by as
much as 38.8% (1997).
In the absence of company-provided data, the analyst must use other sources of informa-
tion to make adjustments. In some cases, data on the cost of capacity are available from in-
dustry sources; this is more likely to be true for relatively homogeneous industries such as
paper, oil re¬ning, and chemicals. Cost per ton of capacity data for such industries is fre-
quently cited in trade publications or can be gleaned from company contacts.
Another possible source of data is actual construction. Companies frequently report the
cost and capacity of new plants. Such data from the company or its competitors can be used
to estimate the current cost of existing facilities.
Yet another approach is the use of construction cost statistics. If the year of construction
of a plant is available, the historical cost can be indexed to estimate the current construction
cost of the same facility.
For real estate assets, current land and construction cost data are frequently included in
industry publications. The analyst can use this data to estimate the current cost of construc-
tion for factories, warehouses, and so forth. For some categories of real estate, especially in-
come-producing properties (of¬ce buildings, shopping centers, hotels), publicly available
market value estimates should be used as the measure of current costs as market value is

Tangible Fixed Assets
Amounts in SKr millions

Years Ended December 31

1997 1998 1999 2000

Forest and Agricultural Property
Acquisition values 285 310 309 312
Accumulated depreciation ” ” ” ”
Accumulated revaluations 14,275 14,275 14,268 14,268
Net carrying value 4,560 4,585 4,577 4,580

Assessed tax values* 8,474 6,050 6,699 7,026

*Sweden only

Excess tax values 3,914 1,465 2,122 2,446

Buildings, Other Land, Etc.
Acquisition values 4,373 5,065 3,341 3,689
Accumulated depreciation (2,432) (2,608) (1,640) (1,756)
Accumulated revaluations 11,108 11,108 11,104 11,104
Net carrying value 2,049 2,565 1,805 2,037

Assessed tax values* 4,496 4,012 2,701 3,149

*Sweden only

Excess tax values 2,447 1,447 896 1,112

Total excess values 6,361 2,912 3,018 3,558

Total tangible assets 19,551 20,707 14,825 16,129
Adjusted tangible assets 25,912 23,619 17,843 19,687
% increase 32.5% 14.1% 20.4% 22.1%

Stockholders™ equity 16,375 18,377 15,883 17,014
Adjusted equity 22,736 21,289 18,901 20,572
% increase 38.8% 15.8% 19.0% 20.9%

Source: Holmen Annual Reports, 1998“2000

more relevant than reproduction cost. Acquisitions accounted for under the purchase method
result in the restatement of acquired ¬xed assets to their fair value or current cost.
In some cases, industry-speci¬c disclosures are available. For example, see the discussion
of the disclosures of the net present value of oil and gas reserves discussed in Appendix 7-B.
All these approaches require estimates. The lack of precision does not mean that the ex-
ercise is not worthwhile. Remember that estimates are present in the reported ¬nancial state-
ments as well.

Using Current Cost Asset Values
The main use for current cost asset data is to prepare a current cost balance sheet. The histor-
ical cost of all assets and liabilities should be replaced with the current cost (market value) of
those assets. As compared with the historical cost balance sheet, a current cost balance sheet

provides a better measurement of the net assets available to management. These data can be
used to make a better evaluation of management™s use of available resources, the borrowing
capacity of the ¬rm, security for creditors, and the liquidation value of the company. These
issues will be discussed more fully in Chapter 17.

Estimating Current Cost Depreciation
Once the current cost of ¬xed assets is estimated, the next step is to estimate depreciation on
a current cost basis. The current cost of ¬xed assets should be amortized over the estimated
economic life of the assets, allowing for salvage values. The arbitrarily chosen depreciation
method and lives used for ¬nancial reporting purposes may not be adequate for this purpose.
For analysis purposes, the choice of depreciation method, lives, and salvage values should be
carefully considered.
It is important to look at overall corporate trends. If real output is static, then one can
argue that all capital expenditures have been made to replace used up capacity. As SFAS 14
requires (see Chapter 13) the disclosure of capital expenditures and depreciation expense
for each reportable segment, this analysis can be done for each segment of a multiindustry
Some companies disclose the cost of major capital projects, allowing the analyst to
“back into” an estimate of “maintenance” expenditures. Other ¬rms provide approximate
data regarding the purpose of current capital expenditures. The portion allocated to the
“maintenance of existing capacity” may be a good proxy for current cost depreciation.6 Re-
member that the goal is to estimate the cost to replace capacity used up during the accounting

Example: Mead.
Exhibit 8A-3 contains ¬nancial statement data for 1996“2000 for Mead [MEA], a major
paper producer. This capital expenditures analysis breaks out the components of capital
spending: growth, maintenance, cost-effectiveness, and environmental. Over the ¬ve-year
period, capital expenditures declined from 215% of depreciation (1996) to 74% (2000).

Capital Expenditures Analysis

Amounts in $millions Years Ended December 31

1996 1997 1998 1999 2000 Totals

Growth* $225.4 $139.7 $158.6 $ 40.2 $ 41.2 $ 605.1
Maintenance 73.9 150.8 79.1 42.8 56.4 403.0
Cost-effective 96.0 122.6 117.3 102.1 83.9 521.9
Environmental 0033.4 0024.2 0029.0 0027.8 0024.4 0.0138.8
Total $428.7 $437.3 $384.0 $212.9 $205.9 $1,668.8

*Including related environmental

Depreciation Expense $199.2 $238.4 $260.3 $263.2 $276.4 $1,237.5

Ratio to depreciation expense:
Total capital expenditure 215% 183% 148% 81% 74% 135%
Non-growth capital expenditure 102% 125% 87% 66% 60% 86%

Source: Data from Mead Annual Reports and Fact Books.

In IAS 7, Cash Flow Statements, the IASB recommends that companies disclose the portion of capital expenditures
required to maintain capacity.

When growth is excluded, the ratio of capital spending to depreciation expense declines from
102% in 1996 to 60% in 2000.
These data raise a number of interesting questions for an analyst to pursue:
1. Mead™s “maintenance” expenditures declined sharply from 1997 to 2000 to levels far
below depreciation expense. While these data suggest that Mead is not truly main-
taining its operating capacity, we believe that “cost-effectiveness” and “environmen-
tal” expenditures should be included.
2. Even so, over the ¬ve-year period, non-growth expenditures were only 86% of de-
preciation expense.7 This suggests that, even by our expanded de¬nition, operating
capacity is being reduced. There may be lines of business that have insuf¬cient prof-
itability or growth potential to warrant new investment.
3. Growth expenditures also declined sharply over this ¬ve-year period (they had risen
rapidly from pre-1996 levels). These changes may re¬‚ect industry conditions, capital
constraints, or strategic decisions by management.
4. Mead has made signi¬cant “cost-effectiveness” investments during this period, cost
reductions are presumably being realized currently, whereas depreciation is under-
stated by the use of historical cost. Such expenditures should increase reported in-
come as a result.
These are examples of how ¬nancial analysis can suggest lines of inquiry about fundamental
business issues. Analysis of segment data and discussion with management should provide
some answers to these questions.

Use of Current Cost Depreciation
Estimates of current cost depreciation should be used to adjust reported income to current
cost. Along with the adjustment to last-in, ¬rst-out (LIFO) when applicable (see Chapter 6),
the replacement of historic cost depreciation by current cost will produce a better measure of
sustainable income.8
Current cost data should also be used to adjust ratios so that they are better measures
of management performance. When prices are increasing, the use of current cost data re-
duces the computed return on equity (ROE) as income is reduced (higher depreciation) and
equity is increased (higher asset values). If the current cost ROE is very low, for example,
it tells us that the company might be better off selling its assets and either reinvesting the
proceeds in other assets, providing higher returns, or distributing them to stockholders for

Using Constant Dollar Data
Although we have stated that constant dollar data are generally not useful for ¬nancial analy-
sis, there are some applications. Constant dollar data can be used to look at investment re-
turns from the investor point of view.
An investor should measure the performance of an investment relative to inflation, not
in absolute terms. Investors defer current consumption to obtain higher future consump-
tion. In highly inflationary societies, the instinct to save is stifled if nominal rates of return
are below the inflation rate. Under these conditions, consumption deferred is consumption
To measure the impact of changing prices on the investor, de¬‚ate returns by a measure
of purchasing power such as the consumer price index. The index for the investor, not the in-
vestment, should be used. For example, an investment in General Motors™ shares by a Cana-
dian investor must be evaluated by de¬‚ating the returns (translated into Canadian dollars) by

In 1994, Mead lengthened its depreciation lives, reducing depreciation expense. This change increases the ratio of
capital expenditures to depreciation expense.
Sustainable income is de¬ned and discussed in Chapter 2.

the Canadian consumer price index. This can be done using the constant dollar method illus-
trated in Exhibit 8A-1.
The constant dollar method is also widely used in highly in¬‚ationary economies, espe-
cially when their ¬nancial systems are indexed to in¬‚ation. In many cases, the constant dol-
lar method (sometimes in modi¬ed form) is used to produce the primary ¬nancial statements
for ¬nancial and/or tax reporting.
Although the analysis of such statements is beyond the scope of this text, we will pro-
vide one caveat. Unless the input and output prices of the ¬rm subjected to analysis are fully
indexed, the constant dollar method will not provide a satisfactory basis for analysis. Sound
investment decisions require an understanding of the effects of the speci¬c price changes
faced by the ¬rm.

International Accounting Standards
IAS 15 (1989) provided for voluntary disclosures similar to those of ASR 190 (previously
discussed). IAS 29 (1989), Financial Reporting in Hyperin¬‚ationary Economies, requires ad-
justment of ¬nancial statements of companies operating in hyperin¬‚ationary economies
using the constant dollar method. The principal provisions of IAS 29 are:
1. The currency unit at the balance sheet date must be used as the unit of measure. All
nonmonetary assets and liabilities must be restated to that unit, using the methodol-
ogy illustrated in Exhibit 8A-1.
2. Balance sheet items carried at current cost are not restated.
3. Losses (gains) on net monetary assets (liabilities) are included in net income for the
4. The portion of borrowing cost that represents the premium for in¬‚ation must be ex-
pensed when debt is indexed for in¬‚ation.
5. Income and cash ¬‚ow statement items must be restated to the same unit of measure
used for the balance sheet.
While IAS 29 does not state when an economy is considered to be hyperin¬‚ationary, it sug-
gests cumulative three-year in¬‚ation of 100% as a guide.9
Although the accounting for hyperin¬‚ationary economies under IAS 29 is quite different
from the treatment under U.S. GAAP (described in Chapter 15),10 the IAS treatment is ac-
ceptable under SEC rules for foreign companies ¬ling in the United States; reconciliation to
U.S. GAAP is not required.

Concluding Remarks
With the adoption of SFAS 89, changing prices disappeared as an accounting issue. Yet
prices continue to change. While general in¬‚ation has remained at low levels in virtually all
industrialized countries, the prices of speci¬c commodities continue to ¬‚uctuate.
Thus, ¬nancial analysis requires identi¬cation of the effects of signi¬cant price changes.
Some of these effects can be dealt with summarily. For example, it is relatively easy to use
an index of retail prices to compute the effect of in¬‚ation on department store sales. It is
more complex (and more dif¬cult) to discern the effect of a change in oil prices on an oil re-
¬ner™s pro¬t margins, turnover ratios, and return on equity. The objective of this appendix,
and the material on the effect of price changes in Chapters 6 through 8, was to provide tools
to permit such analysis.

Cumulative three-year in¬‚ation of 100% is the criterion for hyperin¬‚ationary treatment under SFAS 52, as de-
scribed in Chapter 15.
Under IAS GAAP, hyperinflation is dealt with by inflation-adjusting the subsidiary financial statements; U.S.
GAAP adjusts via the choice of currency used to translate the subsidiary financial statements into the reporting


8A-1. [Income, cash ¬‚ow, and ratio effects of current cost adjustments] Use the data in Ex-
hibit 8A-2 and the Holmen ¬nancial statements to answer the following questions.
A. Estimate current cost depreciation for 1999.
B. Compute Holmen™s net income for 1999 after adjustment for current cost depre-
C. Describe the effect of the adjustment in part A on Holmen™s cash from operations.
D. Compute each of the following ratios for 1999 using both reported and current
cost data. Discuss your results
(i) Fixed asset turnover
(ii) Total asset turnover
(iii) Return on average equity
Appendix 11-A

SFAS 140 (2000) amended SFAS 125 (1996) by changing the conditions under which secu-
ritizations could be treated as sales of receivables. The principal modi¬cations concerned (a)
the criteria used to designate qualifying special purpose entities (transferees purchasing secu-
ritized assets) and (b) conditions under which the transferor retains effective control over the
transferred assets. SFAS 140 requires signi¬cant new disclosures regarding securitized as-
sets. SFAS 140 applied to transfers of ¬nancial assets occurring after March 31, 2001. Early
adoption was prohibited. Sears adopted SFAS 140 on April 1, 2001.
These changes and the new disclosure provisions are illustrated using Sears™ disclosures
from its 2000 and 2001 annual reports. Some of these data were reported in 1999, as part of
the Management Discussion and Analysis.

Part A: Disclosures”Sears 2000 Annual Report

The Company utilizes credit card securitizations as a part of its overall funding strategy.
Under generally accepted accounting principles, if the structure of the securitization meets
certain requirements, these transactions are accounted for as sales of receivables.

Summary of Securitization Process
As part of its domestic credit card securitizations, the Company transfers credit card receiv-
able balances to a Master Trust1 (“Trust”) in exchange for certi¬cates representing undivided
interests in such receivables. Balances transferred from the Company™s credit card portfolio
to the Trust become securities upon transfer. These securities are accounted for as available-
for-sale securities. The allowance for uncollectible accounts that related to the transferred re-
ceivables is amortized over the collection period to recognize income on the transferred
balances on an effective yield basis. This resulted in additional revenues of $60 and $75 mil-
lion in 2000 and 1999, respectively, and did not affect 1998 revenues. The Trust securitizes
balances by issuing certi¬cates representing undivided interests in the Trust™s receivables to
outside investors. In each securitization transaction the Company retains certain subordi-
nated interests that serve as a credit enhancement to outside investors and expose the Com-
pany™s Trust assets to possible credit losses on receivables sold to outside investors. The
investors and the Trust have no recourse against the Company beyond Trust assets.

The Master Trust is the qualifying special purpose entity referred to in the appendix introduction.


In order to maintain the committed level of securitized assets, the Company reinvests
cash collections on securitized accounts in additional balances. These additional investments
result in increases to the interest-only strip and credit revenues. As of December 30, 2000,
the Company™s securitization transactions mature as follows:

2001 $1,046
2002 1,403
2003 2,020
2004 1,519
2005 and thereafter 1,846

Retained Interest in Transferred Credit Card Receivables
The Company™s retained interest in transferred credit card receivables consists of investor
certi¬cates (undivided interests in or claims on cash ¬‚ows of the Trust™s receivables) held by
the Company, interest-only strips (the company™s rights to residual, future cash ¬‚ows after
the outside investors have received the contractual return), contractually required seller™s in-
terest (credit enhancement or support provided by Sears), and excess seller™s interest (receiv-
ables available for future securitizations) in the credit card receivables in the Trust. Retained
interests at year-end are as follows:

Millions 2000 1999

Subordinated interests:
Investor certi¬cates held by the Company $1,161 $ 960
Unsubordinated interests:
Contractually required seller™s interest 898 760
Excess seller™s interest 992 1,455
Interest-only strip 136 67
Less: Unamortized transferred allowance for uncollectible accounts $3,182 $3,231
Retained interest in transferred credit card receivables $3,105 $3,211

The Company intends to hold the investor certi¬cates and contractually required seller™s in-
terest to maturity. The excess seller™s interest is considered available-for-sale. Due to the re-
volving nature of the underlying credit card receivables, the carrying value of the Company™s
retained interest in transferred credit card receivables approximates fair value and is classi-
¬ed as a current asset.

Securitization Gains
Due to the quali¬ed status of the Trust, the issuance of certi¬cates to outside investors is con-
sidered a sale for which the Company recognizes a gain and an asset for the interest-only
strip. The interest-only strip represents the Company™s rights to future cash ¬‚ows arising
after the investors in the Trust have received the return for which they contracted. The Com-
pany also retains servicing responsibilities for which it receives annual servicing fees ap-
proximating 2% of the outstanding balance. The Company recognized incremental operating
income from net securitization gains of $68, $11, and $58 million in 2000, 1999, and 1998,
The Company measures its interest-only strip and the related securitization gains using
the present value of estimated future cash flows. This valuation technique requires the use
of key economic assumptions about yield, payment rates, charge-off rates, and returns to
transferees. Approximately 22% of the Company™s outstanding securitizations offer vari-

able returns to investors with contractual spreads over LIBOR ranging from 16 to 53 basis
As of December 30, 2000, the interest-only strip was recorded at its fair value of $136
million. The following table shows the key economic assumptions used in measuring the
interest-only strip and securitization gains. The table also displays the sensitivity of the cur-
rent fair value of residual cash ¬‚ows to immediate 100 and 200 basis point adverse changes
in yield, payment rate, charge-off, and discount rate assumptions:

Effects of Adverse
Millions Assumptions 100 bp 200 bp

Yield (annual rate) 19.85% $36 $71
Principal payment rate (monthly rate) 5.26% $20 $35
Gross charge-off rate (annual rate) 7.4% $36 $71
Residual cash ¬‚ows discount rate (annual rate) 12.0% $1 $2

These sensitivities are hypothetical and should be used with caution. As the ¬gures indicate,
changes in fair value assumptions generally cannot be extrapolated because the relationship
of the change in assumption to the change in fair value may not be linear. Also, in this table,
the effect of a variation in a particular assumption on the fair value of the retained interest is
calculated without changing any other assumption; in reality, changes in one factor may re-
sult in changes in another, which might magnify or counteract the sensitivities.

Managed Portfolio Data
A summary of the domestic year-end securitized receivables and other domestic credit card
receivables managed together with them follows:

Millions 2000 1999

Securitized balances $ 7,834 $ 6,579
Retained interest in transferred credit card receivables (1) 3,051 3,175
Owned credit card receivables 16,175 17,068
Other customer receivables $ 16,(59) $ 26,(37)
Managed credit card receivables $27,001 $26,785
Net charge-offs of managed credit card receivables $ 1,323 $ 1,713
Delinquency rates at year-end 7.56% 7.58%
(1) The 2000 and 1999 retained interest amounts exclude reserves of $82 and $31 million, respectively, and interest-
only strip balances of $136 and $67 million, respectively, related to the transfer of credit card receivables into the

Securitization Cash Flow Data
The table below summarizes certain cash ¬‚ows that the Company received from and paid to
the securitization trust during 2000:


Proceeds from new securitizations $2,620
Proceeds from collections reinvested in previous securitizations 3,547
Servicing fees received 200
Purchase of charged-off balances, net of recoveries (522)
Source: Sears 2000 Annual Report

Part B: Discussion
The ¬rst part of Note 3 discussed Sears™ policies regarding the securitization of credit card
receivables. While not clearly stated, Sears apparently retains all of the effective credit risk
of these receivables.
Sears discloses the maturity of the securitizations, which extend out for more than ¬ve
years. Nonetheless, Sears reports all of its interest in these receivables (and all receivables
owned) as current assets. Thus, the current ratio of 1.82 overstates the liquidity of Sears™ bal-
ance sheet.
Next, Sears reports its interest in the securitized receivables in several categories:
• Subordinated interests retained by Sears
• Contractual interest
• Excess interest
• Interest-only strip
• Unamortized allowance of uncollectible accounts

As the securitizations meet the requirements of SFAS 125 for sale recognition, Sears recog-
nizes gains when the sales take place. In 2000, such gains were $68 million. The amount of
the gain, and valuation of the interest-only strip depends on the following assumptions:
1. Yield on the sold receivables
2. Monthly customer payment rate
3. Annual charge-off (bad debt) rate
4. Rate used to discount residual cash ¬‚ows
The table discloses Sears™ assumptions, which can be compared with those of other compa-
nies, and the effect of adverse deviations on the valuation of residual cash ¬‚ows.


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