<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event report):AUGUST 29, 2000
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
DELAWARE 000-30176 73-1567067
(State or Other Jurisdiction (Commission File (IRS Employer
of Incorporation or Organization) Number) Identification Number)
20 NORTH BROADWAY, SUITE 1500 OKLAHOMA CITY, OK 73102
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (405) 235-3611
<PAGE> 2
ITEM 5. OTHER EVENTS
On August 29, 2000, Devon Energy Corporation ("Devon") and Santa Fe
Snyder Corporation ("Santa Fe Snyder") completed their merger. The merger was
accounted for under the pooling-of-interests method of accounting for business
combinations. Accordingly, all of Devon's prior period financial data must be
restated to combine its results with those of Santa Fe Snyder as though the two
companies had always been combined.
Presented on the following pages are certain supplemental financial
disclosures that would have been included in Devon's year-end 1999 Annual Report
on Form 10-K had the Santa Fe Snyder merger been completed prior to the end of
1999. The supplemental consolidated financial statements and other financial
disclosures give retroactive effect to the merger of Devon and Santa Fe Snyder,
which has been accounted for as a pooling-of-interests. Accounting principles
generally accepted in the United States of America proscribe giving effect to a
consummated business combination accounted for by the pooling-of-interests
method in financial statements that do not include the date of consummation. The
supplemental financial statements and other financial disclosures included in
this report do not extend through the date of consummation. However, they became
the historical consolidated financial statements of Devon on August 29, 2000.
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Selected Financial Data 4
Management's Discussion and Analysis of Financial Condition and Results of Operations 7
Quantitative and Qualitative Disclosures About Market Risk 19
Independent Auditors' Reports 21
Supplemental Consolidated Financial Statements:
Supplemental Consolidated Balance Sheets - December 31, 1999 and 1998 24
Supplemental Consolidated Statements of Operations - Years Ended December 31, 1999, 1998 and 1997 25
Supplemental Consolidated Statements of Stockholders' Equity - Years Ended December 31, 1999, 1998 and 1997 26
Supplemental Consolidated Statements of Cash Flows - Years Ended December 31, 1999, 1998 and 1997 27
Notes to Supplemental Consolidated Financial Statements - December 31, 1999, 1998 and 1997 28
</TABLE>
Page 2 of 79 pages
<PAGE> 3
DEFINITIONS
As used in this document:
"Mcf" means thousand cubic feet
"MMcf" means million cubic feet
"Bcf" means billion cubic feet
"MMBtu" means million British thermal units, a measure of heating value
"Bbl" means barrel
"MBbls" means thousand barrels
"MMBbls" means million barrels
"Boe" means equivalent barrels of oil
"MBoe" means thousand equivalent barrels of oil
"MMBoe" means million equivalent barrels of oil
"Oil" includes crude oil and condensate
"NGLs" means natural gas liquids
Page 3 of 79 pages
<PAGE> 4
SELECTED FINANCIAL DATA
The following selected financial information (not covered by the
independent auditors' reports) should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations and the
supplemental consolidated financial statements and the notes thereto included
elsewhere in this report. Note 2 to the supplemental consolidated financial
statements included elsewhere in this report contains information on the 2000
merger with Santa Fe Snyder, the 1999 mergers with PennzEnergy Company and
Snyder Oil Corporation and the 1998 combination of Devon and Northstar Energy
Corporation ("Northstar"), as well as unaudited pro forma financial data for the
years 1999 and 1998.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------
1999 1998 1997 1996 1995
----------- ----------- ----------- ----------- -----------
(THOUSANDS, EXCEPT PER SHARE DATA AND RATIOS)
OPERATING RESULTS
<S> <C> <C> <C> <C> <C>
Oil sales $ 553,834 306,924 552,525 582,023 461,706
Gas sales 603,225 328,444 357,559 207,243 148,294
NGLs sales 67,944 24,692 35,820 28,699 15,391
Other revenue 20,596 24,248 48,255 36,470 36,452
----------- ----------- ----------- ----------- -----------
Total revenues 1,245,599 684,308 994,159 854,435 661,843
----------- ----------- ----------- ----------- -----------
Lease operating expenses 303,248 229,884 266,197 259,534 216,924
Production taxes 42,355 22,816 31,027 20,980 14,352
Depreciation, depletion and amortization
of property and equipment 406,375 243,144 285,708 192,107 171,040
Amortization of goodwill 16,111 -- -- -- --
General and administrative expenses 80,645 45,454 53,081 47,411 43,006
Expenses related to mergers 16,800 13,149 -- -- --
Interest expense 109,613 43,532 41,488 48,762 41,285
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term
debt (13,154) 16,104 5,860 199 307
Distributions on preferred securities of
subsidiary trust 6,884 9,717 9,717 4,753 --
Reduction of carrying value of oil and
gas properties 476,100 422,500 641,314 33,100 97,061
----------- ----------- ----------- ----------- -----------
Total costs and expenses 1,444,977 1,046,300 1,334,392 606,846 583,975
----------- ----------- ----------- ----------- -----------
Earnings (loss) before income taxes, minority
interest and extraordinary item (199,378) (361,992) (340,233) 247,589 77,868
Income tax expense (benefit):
Current 23,056 (3,713) 35,757 30,534 7,292
Deferred (72,490) (122,394) (162,499) 58,752 16,069
----------- ----------- ----------- ----------- -----------
Total (49,434) (126,107) (126,742) 89,286 23,361
----------- ----------- ----------- ----------- -----------
Earnings (loss) before minority
interest and extraordinary item (149,944) (235,885) (213,491) 158,303 54,507
Minority interest in Monterey Resources, Inc. -- -- (4,700) (1,300) --
----------- ----------- ----------- ----------- -----------
Earnings (loss) before extraordinary item (149,944) (235,885) (218,191) 157,003 54,507
Extraordinary loss (4,200) -- -- (6,000) --
----------- ----------- ----------- ----------- -----------
Net earnings (loss) $ (154,144) (235,885) (218,191) 151,003 54,507
=========== =========== =========== =========== ===========
Net earnings (loss) applicable to common
shareholders $ (157,795) (235,885) (230,191) 103,803 39,707
=========== =========== =========== =========== ===========
Net earnings (loss) per share before
extraordinary item:
Basic $ (1.64) (3.32) (3.35) 2.08 0.76
Diluted $ (1.64) (3.32) (3.35) 2.03 0.76
Net earnings (loss) per share after
extraordinary item:
Basic $ (1.68) (3.32) (3.35) 1.97 0.76
Diluted $ (1.68) (3.32) (3.35) 1.92 0.76
Cash dividends per common share(1) $ 0.14 0.10 0.09 0.09 0.09
Weighted average common shares outstanding:
Basic 93,653 70,948 68,732 52,744 52,317
Diluted 99,313 76,932 75,366 55,553 52,512
Ratio of earnings to combined fixed charges
and preferred stock dividends(2) N/A N/A N/A 3.90 1.80
</TABLE>
Page 4 of 79 pages
<PAGE> 5
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------------------------------------
1999 1998 1997 1996 1995
----------- ----------- ----------- ----------- -----------
(THOUSANDS)
BALANCE SHEET DATA
<S> <C> <C> <C> <C> <C>
Total assets $ 6,096,360 1,930,537 1,965,386 2,241,890 1,638,710
Debentures exchangeable into shares of
Chevron Corporation common stock $ 760,313 -- -- -- --
Other long-term debt $ 1,656,208 735,871 427,037 361,500 564,537
Convertible preferred securities of
subsidiary trust $ -- 149,500 149,500 149,500 --
Stockholders' equity $ 2,521,320 749,763 1,006,546 1,159,772 739,447
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------
1999 1998 1997 1996 1995
----------- ----------- ----------- ----------- -----------
(THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C>
CASH FLOW DATA
Net cash provided by operating activities $ 532,328 334,471 530,156 393,448 311,836
Net cash used in investing activities $ (768,317) (607,260) (545,683) (471,351) (427,571)
Net cash provided by (used in) financing
activities $ 377,198 256,518 34,859 47,120 100,512
Modified EBITDA(3,5) $ 802,551 373,005 643,854 526,510 387,561
Cash margin(4,5) $ 662,998 323,469 556,892 442,461 338,984
PRODUCTION, PRICE AND OTHER DATA
Production:
Oil (MBbls) 31,756 25,628 32,565 33,180 30,630
Gas (MMcf) 304,203 198,051 186,239 123,286 112,934
NGLs (MBbls) 5,111 3,054 2,842 2,055 1,531
MBoe(6) 87,568 61,691 66,447 55,783 50,983
Average prices:
Oil (Per Bbl) $ 17.44 11.98 16.97 17.54 15.07
Gas (Per Mcf) $ 1.98 1.66 1.92 1.68 1.31
NGLs (Per Bbl) $ 13.29 8.09 12.60 13.97 10.05
Per Boe(6) $ 13.99 10.70 14.24 14.66 12.27
Costs per Boe (6):
Operating costs $ 3.95 4.10 4.47 5.03 4.54
Depreciation, depletion and amortization
of oil and gas properties $ 4.46 3.74 4.17 3.31 3.26
General and administrative expenses $ 0.92 0.74 0.80 0.85 0.84
</TABLE>
(1) Cash dividends per share are presented based on the combined amount of
dividends paid by Devon, Santa Fe Snyder and Northstar in each year. The
dividends per share are also based on the number of shares outstanding in
each year assuming the Santa Fe Snyder merger and the Northstar combination
had been consummated as of the beginning of the earliest year presented.
Santa Fe Snyder did not pay any dividends in any of the years presented.
Northstar did not pay any dividends in 1997, or in 1998 prior to the
closing of the Northstar combination. Also, Northstar's dividends paid in
1996 and 1995 were at rates per share that were different from the rates
paid by Devon in those years. Because of these facts, the cash dividends
per share presented for 1995 through 1999 are not representative of the
actual amounts paid by Devon on an historical basis. For the years 1999,
1998, 1997, 1996 and 1995, Devon's historical cash dividends per share were
$0.20, $0.20, $0.20, $0.14 and $0.12, respectively.
(2) For purposes of calculating the ratio of earnings to combined fixed charges
and preferred stock dividends, (i) earnings consist of earnings before
income taxes, plus fixed charges; (ii) fixed charges consist of interest
expense, deferred effect of changes in foreign currency exchange rate on
long-term debt, distributions on preferred securities of subsidiary trust,
amortization of costs relating to indebtedness and the preferred securities
of subsidiary trust, and one-third of rental expense estimated to be
attributable to interest; and (iii) preferred stock dividends consist of
the amount of pre-tax earnings required to pay dividends on the outstanding
preferred stock. For the years 1999, 1998 and 1997, earnings were
insufficient to cover combined fixed charges and preferred stock dividends
by $205.3 million, $362.0 million and $346.0 million, respectively.
Page 5 of 79 pages
<PAGE> 6
(3) Modified EBITDA represents earnings before interest (including deferred
effect of changes in foreign currency exchange rate on subsidiary's
long-term debt, and distributions on preferred securities of subsidiary
trust), taxes, depreciation, depletion and amortization and reduction of
carrying value of oil and gas properties.
(4) "Cash margin" equals total revenues less cash expenses. Cash expenses are
all expenses other than the non-cash expenses of depreciation, depletion
and amortization, deferred effect of changes in foreign currency exchange
rate on subsidiary's long-term debt, reduction of carrying value of oil and
gas properties and deferred income tax expense. Cash margin measures the
net cash which is generated by a company's operations during a given
period, without regard to the period such cash is actually physically
received or spent by the company. This margin ignores the non-operational
effect on a company's "net cash provided by operating activities", as
measured by generally accepted accounting principles, from a company's
activities as an operator of oil and gas wells. Such activities produce net
increases or decreases in temporary cash funds held by the operator which
have no effect on net earnings of the company.
(5) Modified EBITDA is presented because it is commonly accepted in the oil and
gas industry as a financial indicator of a company's ability to service or
incur debt. Cash margin is presented because it is commonly accepted in the
oil and gas industry as a financial indicator of a company's ability to
fund capital expenditures or service debt. Modified EBITDA and cash margin
are also presented because investors routinely request such information.
Management interprets the trends of modified EBITDA and cash margin in a
similar manner as trends in net earnings.
Modified EBITDA and cash margin should be used as supplements to, and not
as substitutes for, net earnings and net cash provided by operating
activities determined in accordance with generally accepted accounting
principles as measures of Devon's profitability or liquidity. There may be
operational or financial demands and requirements that reduce management's
discretion over the use of modified EBITDA and cash margin. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" included elsewhere in this report. Modified EBITDA and cash
margin may not be comparable to similarly titled measures used by other
companies.
(6) Gas volumes are converted to Boe or MBoe at the rate of six Mcf of gas per
barrel of oil, based upon the approximate relative energy content of
natural gas and oil, which rate is not necessarily indicative of the
relationship of oil and gas prices. The respective prices of oil, gas and
NGLs are affected by market and other factors in addition to relative
energy content.
Page 6 of 79 pages
<PAGE> 7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion and analysis addresses changes in Devon's
financial condition and results of operations during the three year period of
1997 through 1999. Reference is made to "Selected Financial Data" and
"Supplemental Consolidated Financial Statements" included elsewhere in this
report.
OVERVIEW
On August 29, 2000, Devon and Santa Fe Snyder Corporation ("Santa Fe
Snyder") closed their merger that was previously announced on May 25, 2000. As
of the merger closing date, Devon issued approximately 40.6 million shares of
common stock. The merger added $1.4 billion of assets and $730.9 million of
long-term debt and $492.7 million of other liabilities to Devon's pre-merger
balance sheet as of the end of August 2000. As of December 31, 1999, the merger
added 386.3 million Boe of reserves and 15.9 million net acres of undeveloped
leasehold. The Santa Fe Snyder merger was accounted for under the
pooling-of-interests method of accounting for business combinations.
Accordingly, although the merger was not closed until 2000, Devon's results for
the first eight months of 2000 and all fiscal years prior to 2000 have been
restated to include the results of both Devon and Santa Fe Snyder as if the two
companies had always been combined.
On August 17, 1999, Devon and PennzEnergy Company ("PennzEnergy")
closed their merger that was previously announced on May 20, 1999. In the
merger, Devon issued approximately 21.5 million shares of common stock and
assumed $1.6 billion of long-term debt and $0.7 billion of other liabilities.
The merger added 396 million Boe of reserves, 13 million net acres of
undeveloped leasehold and $3.2 billion of assets to Devon's balance sheet. This
significantly expanded the scope of Devon's operations and moved Devon into the
top ten of all U.S.-based independent oil and gas producers.
The PennzEnergy merger was accounted for under the purchase method of
accounting for business combinations. Therefore, Devon's 1999 results do not
include any effect of PennzEnergy's operations prior to August 17, 1999.
On May 5, 1999, Santa Fe Energy and Snyder Oil Company closed their
merger that was previously announced on January 13, 1999. In the merger 15.3
million shares of Devon common stock (as adjusted for the Devon-Santa Fe Snyder
pooling) were issued. Approximately $219.0 million of long-term debt and $216.8
million of other liabilities were assumed. The Snyder merger was accounted for
under the purchase method of accounting for business combinations. Therefore,
Devon's 1999 results do not include any effect of Snyder's operations prior to
May 5, 1999.
The PennzEnergy merger was completed less than a year after Devon's
merger with Northstar Energy Corporation ("Northstar"). The December 10, 1998,
combination of Devon and Northstar added 115 million Boe of proved reserves and
1.8 million undeveloped acres, all in Canada. The Northstar combination was
accounted for under the pooling-of-interests method of accounting for business
combinations. Accordingly, Devon's results for 1998 and prior years include the
results of both Devon and Northstar as if the two had always been combined.
On July 25, 1997, the stock of Monterey Resources, Inc. was distributed
to the then shareholders of Santa Fe Energy through a tax-free distribution.
Accordingly, Devon's 1997 consolidated results of operations only include the
first seven months of Monterey's 1997 results.
In addition to mergers, Devon's exploration, drilling and development
efforts have also been significant contributors to Devon's growth over the three
years from 1997 through 1999. Excluding the pooled results of Santa Fe Snyder
for all periods, and excluding the pooled results of Northstar prior to December
1998, Devon has spent approximately $492 million in its exploration, drilling
and development efforts from 1997 through 1999. These costs included drilling
1,154 wells, of which 1,065 were completed as producers.
Page 7 of 79 pages
<PAGE> 8
The impact of mergers and drilling activities include the following
changes from 1997 to 1999. (The following changes are calculated using 1997's
results without combining Santa Fe Snyder's results or Northstar's results, and
the 1999 results include the effects of the added PennzEnergy operations for
only the last 4 1/2 months of the year. The 1999 results do not include the
combined pooled results of Santa Fe Snyder.)
o Combined oil, gas and NGLs production increased 32.3 million Boe,
or 160%.
o Combined oil, gas and NGLs revenues increased $409.8 million, or
134%, during a period when the average combined price of oil, gas
and NGLs fell by $1.53 per Boe, or 10%.
o Net cash provided by operating activities increased $36.9
million, or 22%. Cash margin increased $210.9 million, or 116%.
o Net earnings increased $19.3 million, or 26%.
o Production and operating expenses per Boe dropped $0.52 per Boe,
or 19%.
o Depreciation, depletion and amortization of oil and gas
properties per Boe increased $0.58 per Boe, or 14%.
o General and administrative expenses per Boe increased $0.39 per
Boe, or 61%. However, Devon expects to eliminate a substantial
part of this increase in costs per Boe in 2000 due to the
termination at the end of 1999 of certain commitments inherited
as part of the PennzEnergy merger.
During 1999, Devon marked its eleventh anniversary as a public company.
While Devon has consistently increased production over this eleven-year period,
volatility in oil and gas prices has resulted in considerable variability in
earnings and cash flows. Prices for oil, natural gas and NGLs are determined
primarily by market conditions. Market conditions for these products have been,
and will continue to be, influenced by regional and world-wide economic growth,
weather and other factors that are beyond Devon's control. Devon's future
earnings and cash flows will continue to depend on market conditions.
Like all oil and gas production companies, Devon faces the challenge of
natural production decline. As virgin pressures are depleted, oil and gas
production from a given well naturally decreases. Thus, an oil and gas
production company depletes part of its asset base with each unit of oil or gas
it produces. Historically, Devon has been able to overcome this natural decline
by adding, through drilling and acquisitions, more reserves than it produces.
Devon's future growth, if any, will depend on its ability to continue to add
reserves in excess of production.
Because oil and gas prices are influenced by many factors outside of
its control, Devon's management has focused its efforts on increasing oil and
gas reserves and production and controlling expenses. Over its eleven year
history as a public company, Devon has been able to significantly reduce its
operating costs per unit of production. Devon's future earnings and cash flows
are dependent on its ability to continue to contain operating costs at levels
that allow for profitable production of its oil and gas reserves.
Page 8 of 79 pages
<PAGE> 9
RESULTS OF OPERATIONS
(The following discussion of Devon's results of operations from 1997
through 1999 include the restated results of Devon for the 2000 merger with
Santa Fe Snyder and the 1998 combination with Northstar, both of which were
accounted for using the pooling-of-interests method.)
Devon's total revenues have risen from $994.2 million in 1997 to $1.2
billion in 1999. In each of these three years, oil, gas and NGLs sales accounted
for over 94% of total revenues.
Changes in oil, gas and NGLs production, prices and revenues from 1997
to 1999 are shown in the following tables. (Unless otherwise stated, all dollar
amounts are expressed in U.S. dollars.)
<TABLE>
<CAPTION>
TOTAL
----------------------------------------------------------------------
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
1999 1998
1999 VS 1998 1998 VS 1997 1997
----------- --------- --------- --------- --------
(ABSOLUTE AMOUNTS IN THOUSANDS)
PRODUCTION
<S> <C> <C> <C> <C> <C>
Oil (MBbls)................ 31,756 +24% 25,628 (21)% 32,565
Gas (MMcf)................. 304,203 +54% 198,051 +6 % 186,239
NGLs (MBbls)............... 5,111 +67% 3,054 +7 % 2,842
Oil, gas and NGLs (MBoe)... 87,568 +42% 61,691 (7)% 66,447
REVENUES
Per Unit of Production:
Oil (per Bbl)............ $ 17.44 +46% 11.98 (29)% 16.97
Gas (per Mcf)............ $ 1.98 +19% 1.66 (14)% 1.92
NGLs (per Bbl)........... $ 13.29 +64% 8.09 (36)% 12.60
Oil, gas and NGLs (per Boe) $ 13.99 +31% 10.70 (25)% 14.24
Absolute:
Oil...................... $ 553,834 +80% 306,924 (44)% 552,525
Gas...................... $ 603,225 +84% 328,444 (8)% 357,559
NGLs..................... $ 67,944 +175% 24,692 (31)% 35,820
----------- --------- --------
Oil, gas and NGLs........ $ 1,225,003 +86% 660,060 (30)% 945,904
=========== ========= ========
</TABLE>
Page 9 of 79 pages
<PAGE> 10
<TABLE>
<CAPTION>
DOMESTIC
--------------------------------------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------
1999 1998
1999 VS 1998 1998 VS 1997 1997
--------- --------- --------- --------- --------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
PRODUCTION
Oil (MBbls)................ 17,822 +45% 12,257 (48)% 23,500
Gas (MMcf)................. 221,061 +82% 121,419 +3 % 117,520
NGLs (MBbls)............... 4,396 +78% 2,468 +3 % 2,396
Oil, gas and NGLs (MBoe)... 59,062 +69% 34,962 (23)% 45,483
REVENUES
Per Unit of Production:
Oil (per Bbl)............ $ 18.47 +50% 12.35 (28)% 17.14
Gas (per Mcf)............ $ 2.19 +14% 1.92 (15)% 2.27
NGLs (per Bbl)........... $ 13.11 +63% 8.05 (36)% 12.49
Oil, gas and NGLs
(per Boe)............ $ 14.75 +28% 11.56 (25)% 15.38
Absolute:
Oil...................... $ 329,162 +117% 151,386 (62)% 402,704
Gas...................... $ 484,430 +108% 233,073 (43)% 266,918
NGLs..................... $ 57,610 +190% 19,871 (34)% 29,938
--------- --------- --------
Oil, gas and NGLs........ $ 871,202 +115% 404,330 (42)% 699,560
========= ========= ========
</TABLE>
<TABLE>
<CAPTION>
CANADA
--------------------------------------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------
1999 1998
1999 VS 1998 1998 VS 1997 1997
--------- --------- --------- --------- --------
(ABSOLUTE AMOUNTS IN THOUSANDS)
PRODUCTION
<S> <C> <C> <C> <C> <C>
Oil (MBbls)................ 5,178 (17)% 6,257 + 9% 5,728
Gas (MMcf)................. 73,561 +10% 67,158 +10% 60,795
NGLs (MBbls)............... 700 +24% 566 +34% 423
Oil, gas and NGLs (MBoe)... 18,138 +1% 18,016 +11% 16,284
REVENUES
Per Unit of Production:
Oil (per Bbl)............ $ 14.71 +26% 11.72 (27)% 16.10
Gas (per Mcf)............ $ 1.45 +17% 1.24 (6)% 1.32
NGLs (per Bbl)........... $ 14.33 +76% 8.16 (38)% 13.20
Oil, gas and NGLs
(per Boe)............ $ 10.65 +19% 8.94 (18)% 10.95
Absolute:
Oil...................... $ 76,171 +4% 73,338 (20)% 92,221
Gas...................... $ 106,895 +29% 83,071 +3% 80,441
NGLs..................... $ 10,034 +117% 4,621 (17)% 5,582
--------- --------- --------
Oil, gas and NGLs........ $ 193,100 +20% 161,030 (10)% 178,244
========= ========= ========
</TABLE>
<TABLE>
<CAPTION>
INTERNATIONAL
--------------------------------------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------
1999 1998
1999 VS 1998 1998 VS 1997 1997
--------- --------- --------- --------- --------
(ABSOLUTE AMOUNTS IN THOUSANDS)
PRODUCTION
<S> <C> <C> <C> <C> <C>
Oil (MBbls)................ 8,756 +23% 7,114 +113 % 3,337
Gas (MMcf)................. 9,581 +1% 9,474 +20 % 7,924
NGLs (MBbls)............... 15 (25)% 20 (13)% 23
Oil, gas and NGLs (MBoe)... 10,368 +19% 8,713 +86 % 4,681
REVENUES
Per Unit of Production:
Oil (per Bbl)............ $ 16.96 +47% 11.55 (33)% 17.26
Gas (per Mcf)............ $ 1.24 (5)% 1.30 +1 % 1.29
NGLs (per Bbl)........... $ 20.00 +100% 10.00 (23)% 13.04
Oil, gas and NGLs
(per Boe)............... $ 15.50 +43% 10.87 (25)% 14.55
Absolute:
Oil...................... $ 148,501 +81% 82,200 +43 % 57,600
Gas...................... $ 11,900 (3)% 12,300 +21 % 10,200
NGLs..................... $ 300 +50% 200 (33)% 300
--------- --------- --------
Oil, gas and NGLs........ $ 160,701 +70% 94,700 +39 % 68,100
========= ========= ========
</TABLE>
Page 10 of 79 pages
<PAGE> 11
OIL REVENUES 1999 VS. 1998 Oil revenues increased $246.9 million in
1999. Oil revenues increased $173.5 million due to a $5.46 per barrel increase
in the average price of oil in 1999. An increase in 1999's production of 6.1
million barrels caused oil revenues to increase by $73.4 million. The August
1999 PennzEnergy merger added 5.3 million barrels of production during the last
4 1/2 months of 1999, and the Snyder merger (the May 1999 merger between Santa
Fe Energy Resources, Inc. and Snyder Oil Company that formed Santa Fe Snyder)
added 1.1 million barrels of production during the last seven months of 1999.
This increase was partially offset by a 0.3 million barrel decline in 1999
production from Devon's other properties.
1998 VS. 1997 Oil revenues decreased $245.6 million in 1998. An average
price decline of $4.99 per barrel reduced revenues by $127.9 million. A 6.9
million barrel decrease in 1998's production caused oil revenues to drop by
$117.7 million. The production decline in 1998 was primarily due to the effect
of the spin-off of Monterrey Resources, Inc., a former subsidiary of Santa Fe
Snyder ("the Monterrey Spin-Off") in 1997. Production volumes for the first
seven months of 1997 prior to the spin-off included 10.7 million barrels
attributed to Monterrey. The volumes lost from the Monterey Spin-Off were
partially offset in 1998 by increased international production in Indonesia,
Gabon and Argentina. International oil production increased 3.8 million barrels
in 1998.
GAS REVENUES 1999 VS. 1998 Gas revenues increased $274.8 million in
1999. A 106.2 Bcf increase in production in 1999 added $176.0 million of gas
revenues compared to 1998. A $0.32 per Mcf increase in the average gas price in
1999 contributed $98.8 million of the increase in gas revenues.
The largest contributor to the 1999 production increase was production
added by the PennzEnergy and Snyder mergers. The PennzEnergy properties added
55.5 Bcf of production during the 4 1/2 months following the PennzEnergy merger.
The Snyder properties added 36.9 Bcf of production during the last seven months
following the May 1999 Snyder merger. A 6.4 Bcf increase in Devon's Canadian gas
production also contributed to the increase in 1999 gas production. The Canadian
gas production increase was primarily the result of two 1998 acquisitions.
Gas production from Devon's historical domestic properties also
increased 7.3 Bcf in 1999. This included a 3.9 Bcf increase in production from
Devon's San Juan Basin coal seam gas properties. These properties produced 23.8
Bcf of gas in 1999 compared to 19.9 Bcf in 1998. This increase was largely the
result of a program of mechanical improvements implemented at the Northeast
Blanco Unit coal seam gas property during 1998.
1998 VS. 1997 Gas revenues decreased $29.1 million in 1998. An average
price decline of $0.26 per Mcf reduced revenues by $51.8 million. This was
partially offset by higher production in 1998. A production increase of 11.8 Bcf
in 1998 added gas revenues of $22.7 million. The production increase was
primarily attributable to Canadian production, which increased 6.4 Bcf in 1998.
This increase was largely caused by a March 1997 acquisition that added a full
twelve months of production in 1998 compared to only nine months of production
in 1997. Domestic production increased 3.9 Bcf in 1998, of which 2.3 Bcf was due
to increased production from the San Juan Basin coal seam gas properties. These
properties produced 19.9 Bcf in 1998 compared to 17.6 Bcf in 1997. The majority
of the production gains realized in 1998 were the result of improvements at the
Northeast Blanco Unit property.
NGLS REVENUES 1999 VS. 1998 NGLs revenues increased $43.3 million in
1999. An increase in 1999's average price of $5.20 per barrel caused NGLs
revenues to increase $26.7 million. A production increase of 2.1 million barrels
in 1999 caused revenues to increase $16.6 million. Production from the
PennzEnergy properties for the last 4 1/2 months of 1999 accounted for 1.7
million barrels of the 1999 increase.
1998 VS. 1997 NGLs revenues decreased $11.1 million in 1998. An average
price decline of $4.51 per barrel caused revenues to drop by $13.8 million. This
decline was slightly offset by production increases of 212,000 barrels. Such
production gains added $2.7 million of revenues in 1998.
OTHER REVENUES 1999 VS. 1998 Other revenues decreased $3.7 million in
1999. Other revenues in 1998 included $8.8 million of one-time revenues
recognized by Northstar in 1998 from terminations of certain management
Page 11 of 79 pages
<PAGE> 12
agreements and gas contracts, and $4.7 million of interest income from federal
income tax audits recognized by Santa Fe Snyder. In comparing 1999 to 1998,
these nonrecurring revenues in 1998 more than offset increases of $9.8 million
in 1999 from other sources of other revenues, including dividend income, other
interest income and third-party gas processing revenues. Other revenues in 1999
included $6.7 million of dividend income in the last 4 1/2 months of the year
from the 7.1 million shares of Chevron Corporation common stock acquired by
Devon in the PennzEnergy merger.
1998 VS. 1997 Other revenues decreased $24.0 million in 1998. This
decrease was primarily due to Northstar's $29.4 million of gains from asset
sales in 1997 which did not recur in 1998, partially offset by the $4.7 million
of interest income recorded in 1998 related to federal income tax audits and
$0.7 million of other miscellaneous increases in other revenue sources.
EXPENSES The details of the changes in pre-tax expenses between 1997
and 1999 are shown in the table below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------
1999 1998
1999 VS 1998 1998 VS 1997 1997
---------- --------- ---------- ---------- ----------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Absolute:
Production and operating expenses:
Lease operating expenses.............................. $ 303,248 +32% 229,884 (14)% 266,197
Production taxes...................................... 42,355 +86% 22,816 (26)% 31,027
Depreciation, depletion and amortization of
oil and gas properties................................ 390,117 +69% 230,419 (17)% 276,977
Amortization of goodwill................................ 16,111 N/A -- -- --
---------- ---------- ----------
Subtotal............................................ 751,831 +56% 483,119 (16)% 574,201
Depreciation and amortization of non-oil and
gas properties........................................ 16,258 +28% 12,725 +46 % 8,731
General and administrative expenses..................... 80,645 +77% 45,454 (14)% 53,081
Expenses related to mergers............................. 16,800 +28% 13,149 N/A --
Interest expense........................................ 109,613 +152% 43,532 +5% 41,488
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt.......... (13,154) N/A 16,104 +175% 5,860
Distributions on preferred securities of
subsidiary trust...................................... 6,884 (29)% 9,717 -- 9,717
Reduction of carrying value of oil and gas
properties............................................ 476,100 +13% 422,500 (34)% 641,314
---------- ---------- ----------
Total............................................... $1,444,977 +38% 1,046,300 (22)% 1,334,392
========== ========== ==========
Per Boe:
Production and operating expenses:
Lease operating expenses.............................. $ 3.46 (7)% 3.72 (7)% 4.01
Production taxes...................................... 0.48 +30% 0.37 (20)% 0.46
Depreciation, depletion and amortization of
oil and gas properties................................ 4.46 (38)% 3.74 (10)% 4.17
Amortization of goodwill................................ 0.18 N/A -- -- --
---------- ---------- ----------
Subtotal............................................ 8.58 +10% 7.83 (9)% 8.64
Depreciation and amortization of non-oil and
gas properties(1)..................................... 0.19 (10)% 0.21 +62% 0.13
General and administrative expenses(1).................. 0.92 +24% 0.74 (8)% 0.80
Expenses related to prior mergers(1).................... 0.19 (10)% 0.21 N/A --
Interest expense(1)..................................... 1.25 +79% 0.70 +13% 0.62
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt(1)....... (0.15) N/A 0.26 +188% 0.09
Distributions on preferred securities of
subsidiary trust(1)................................... 0.08 (50)% 0.16 +7% 0.15
Reduction of carrying value of oil and gas
properties(1)......................................... 5.44 (21)% 6.85 (29)% 9.65
---------- ---------- ----------
Total................................................ $ 16.50 (3)% 16.96 (16)% 20.08
========== ========== ==========
</TABLE>
(1) Though per Boe amounts for these expense items may be helpful for
profitability trend analysis, these expenses are not directly attributable to
production volumes.
Page 12 of 79 pages
<PAGE> 13
PRODUCTION AND OPERATING EXPENSES The details of the changes in
production and operating expenses between 1997 and 1999 are shown in the table
below.
<TABLE>
<CAPTION>
TOTAL
---------------------------------------------------------------
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1999 1998
1999 VS 1998 1998 VS 1997 1997
--------- ---------- ---------- ---------- ----------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Absolute:
Recurring lease operating expenses $ 295,478 +33% 222,639 (14)% 260,258
Well workover expenses 7,770 +7% 7,245 +22% 5,939
Production taxes 42,355 +86% 22,816 (26)% 31,027
--------- ---------- ----------
Total production and operating expenses $ 345,603 +37% 252,700 (15)% 297,224
========= ========== ==========
Per Boe
Recurring lease operating expenses $ 3.37 (7)% 3.61 (8)% 3.92
Well workover expenses 0.09 (18)% 0.11 +22 % 0.09
Production taxes 0.48 +30% 0.37 (20)% 0.46
--------- ---------- ----------
Total production and operating expenses $ 3.94 (4)% 4.09 (9)% 4.47
========= ========== ==========
</TABLE>
<TABLE>
<CAPTION>
DOMESTIC
---------------------------------------------------------------
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1999 1998
1999 VS 1998 1998 VS 1997 1997
--------- ---------- ---------- ---------- ----------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Absolute:
Recurring lease operating expenses $ 186,592 +49% 125,374 (34)% 189,038
Well workover expenses 6,425 +19% 5,400 +23% 4,374
Production taxes 40,592 +95% 20,855 (28)% 29,046
--------- ---------- ----------
Total production and operating expenses $ 233,609 +54% 151,629 (32)% 222,458
========= ========== ==========
Per Boe:
Recurring lease operating expenses $ 3.16 (12)% 3.59 (14)% 4.16
Well workover expenses 0.11 (27)% 0.15 +67% 0.09
Production taxes 0.69 15% 0.60 (6)% 0.64
--------- ---------- ----------
Total production and operating expenses $ 3.96 (9)% 4.34 (11)% 4.89
========= ========== ==========
</TABLE>
<TABLE>
<CAPTION>
CANADA
---------------------------------------------------------------
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1999 1998
1999 VS 1998 1998 VS 1997 1997
--------- ---------- ---------- ---------- ----------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Absolute:
Recurring lease operating expenses $ 48,891 +5% 46,634 +12% 41,769
Well workover expenses 940 (26)% 1,276 +26% 1,016
Production taxes 1,363 (18)% 1,661 +5% 1,581
--------- ---------- ----------
Total production and operating expenses $ 51,194 +3% 49,571 +12% 44,366
========= ========== ==========
Per Boe:
Recurring lease operating expenses $ 2.70 +4% 2.59 +1% 2.56
Well workover expenses 0.05 (29)% 0.07 +17% 0.06
Production taxes 0.07 (22)% 0.09 (10)% 0.10
--------- ---------- ----------
Total production and operating expenses $ 2.82 +3% 2.75 +1% 2.72
========= ========== ==========
</TABLE>
<TABLE>
<CAPTION>
INTERNATIONAL
---------------------------------------------------------------
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1999 1998
1999 VS 1998 1998 VS 1997 1997
--------- ---------- ---------- ---------- ----------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Absolute:
Recurring lease operating expenses $ 59,995 +18 % 50,631 +72% 29,451
Well workover expenses 405 (29)% 569 +4% 549
Production taxes 400 +33 % 300 (25)% 400
--------- ---------- ----------
Total production and operating expenses $ 60,800 +18 % 51,500 +69% 30,400
========= ========== ==========
Per Boe:
Recurring lease operating expenses $ 5.79 -- % 5.81 (8)% 6.29
Well workover expenses 0.04 (43)% 0.07 (42)% 0.12
Production taxes 0.03 -- % 0.03 (62)% 0.08
--------- ---------- ----------
Total production and operating expenses $ 5.86 (1)% 5.91 (9)% 6.49
========= ========== ==========
</TABLE>
Page 13 of 79 pages
<PAGE> 14
1999 VS. 1998 Recurring lease operating expenses increased $72.8
million, or 33%, in 1999. Domestic expenses increased $61.2 million in 1999 due
to $55.8 million of expenses for the last 4 1/2 months of the year from the
PennzEnergy properties, and $17.7 million of expenses for the last seven months
of the year from the Snyder properties. Other than the added costs from the
PennzEnergy and Snyder properties, recurring expenses on Devon's other domestic
properties dropped $12.3 million in 1999. Efficiencies achieved in certain of
Devon's oil producing properties contributed a substantial portion of this cost
reduction.
The majority of Devon's production taxes are assessed on its onshore
domestic properties. In the U.S., most of the production taxes are based on a
fixed percentage of revenues. Therefore, the 115% increase in domestic oil, gas
and NGLs revenues was the primary cause of the 95% increase in domestic
production taxes. Production taxes did not increase proportionately to the
increase in revenues. This was primarily due to the addition in 1999 of gas
revenues from offshore Gulf of Mexico properties acquired in the PennzEnergy
merger. Revenues generated from such offshore properties do not incur state
production taxes.
1998 VS. 1997 Recurring lease operating expenses decreased $37.6
million, or 14%, in 1998. This was due to the $70.1 million of recurring
expenses incurred in the first seven months of 1997 on the Monterey properties
prior to the Monterey Spin-Off. Excluding the effect of the Monterey Spin-Off,
recurring lease operating expenses increased $32.5 million in 1998. The majority
of this increase was in the International division, where recurring expenses
increased $21.1 million in 1998. The increase in International expenses was
attributable to the 86% increase in International production in 1998
As previously stated, most of the U.S. production taxes are based on a
fixed percentage of revenues. Therefore, the 42% drop in 1998 domestic oil, gas
and NGLs revenues was the primary cause of the 28% decrease in domestic
production taxes.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") Devon's largest
recurring non-cash expense is DD&A. DD&A of oil and gas properties is calculated
as the percentage of total proved reserve volumes produced during the year,
multiplied by the net capitalized investment in those reserves including
estimated future development costs (the "depletable base"). Generally, if
reserve volumes are revised up or down, then the DD&A rate per unit of
production will change inversely. However, if the depletable base changes, then
the DD&A rate moves in the same direction. The per unit DD&A rate is not
affected by production volumes. Absolute or total DD&A, as opposed to the rate
per unit of production, generally moves in the same direction as production
volumes. Oil and gas property DD&A is calculated separately on a
country-by-country basis.
1999 VS. 1998 Oil and gas property related DD&A increased $159.7
million, or 69%, in 1999. Oil and gas property related DD&A expense increased
$96.7 million due to the 42% increase in oil, gas and NGLs production in 1999.
Oil and gas property related DD&A increased $63.0 million due to an increase in
the consolidated DD&A rate. The consolidated DD&A rate increased from $3.74 per
Boe in 1998 to $4.46 per Boe in 1999. The 1999 rate of $4.46 per Boe was a
blended rate of before and after the PennzEnergy and Snyder mergers.
Non-oil and gas property DD&A increased $3.5 million in 1999 compared
to 1998. Depreciation of the non-oil and gas properties acquired in the
PennzEnergy and Snyder mergers and depreciation of Devon's new Wyoming gas
pipeline and gathering system, accounted for the increase in 1999's expense.
1998 VS. 1997 Oil and gas property related DD&A decreased $46.6
million, or 17%, in 1998. A 10% drop in the consolidated DD&A rate per Boe from
$4.16 in 1997 to $3.74 in 1998 reduced 1998's DD&A expense by $26.8 million. The
$641.3 million reduction in the carrying value of oil and gas properties
recorded at the end of 1997 was the primary cause of the drop in the 1998 DD&A
rate. Also, the 7% decrease in combined oil, gas and NGLs production in 1998
caused oil and gas property related DD&A expense to drop by $19.8 million in
1998.
AMORTIZATION OF GOODWILL In connection with the PennzEnergy merger,
Devon recorded $338.9 million of goodwill. The goodwill recorded was allocated
$312.0 million to domestic properties and $26.9 million to international
Page 14 of 79 pages
<PAGE> 15
properties. The goodwill is being amortized using the units-of-production
method. Substantially all of the $16.1 million of amortization recognized in
1999 was related to the domestic balance.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon's net G&A consists of
three primary components. The largest of these components is the gross amount of
expenses incurred for personnel costs, office expenses, professional fees and
other G&A items. The gross amount of these expenses is partially reduced by two
offsetting components. One is the amount of G&A capitalized pursuant to the full
cost method of accounting. The other is the amount of G&A reimbursed by working
interest owners of properties for which Devon serves as the operator. These
reimbursements are received during both the drilling and operational stages of a
property's life. The gross amount of G&A incurred, less the amounts capitalized
and reimbursed, is recorded as net G&A in the consolidated statements of
operations. See following table for a summary of G&A expenses by component.
<TABLE>
<CAPTION>
TOTAL
-------------------------------------------------------------
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------
1999 1998
1999 VS 1998 1998 VS 1997 1997
--------- -------- -------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Gross G&A................ $ 150,441 +57% 95,589 (5)% 100,932
Capitalized G&A.......... (28,878) +95% (14,812) +2% (14,475)
Reimbursed G&A........... (40,918) +16% (35,323) +6% (33,376)
--------- -------- --------
Net G&A................ $ 80,645 +77% 45,454 (14)% 53,081
========= ======== =========
</TABLE>
1999 VS. 1998 Net G&A increased $35.2 million in 1999. Gross G&A
increased $54.9 million in 1999. Included in the increase in gross expenses were
$36.7 million of expenses related to 4 1/2 months of the PennzEnergy operations.
The PennzEnergy amounts included $4.4 million of nonrecurring retention bonuses
paid to certain PennzEnergy employees as an inducement to remain with Devon for
two months following the merger closing.
G&A was lowered $14.1 million due to an increase in the amount
capitalized as part of oil and gas properties. The 1999 amount capitalized
included $5.5 million related to the PennzEnergy operations for the last 4 1/2
months of the year. G&A was also reduced by a $5.6 million increase in the
amount of reimbursements on operated properties. The 1999 reimbursements
received from the PennzEnergy properties were $6.0 million.
1998 VS. 1997 Net G&A decreased $7.6 million in 1998. Gross G&A
decreased $5.3 million in 1998. These decreases were due to the expenses
incurred in the first seven months of 1997 on the Monterey properties prior to
the Monterey Spin-Off. Through July 1997, gross G&A related to these properties
was $10.0 million, and net G&A on such properties was $7.1 million.
EXPENSES RELATED TO MERGERS Approximately $16.8 million of expenses
were incurred by Santa Fe Snyder in 1999 related to the Snyder merger. These
costs included $14.4 million related to compensation plans and other benefits,
and $1.9 million of severance and relocation costs. The $16.8 million of costs
related to the operations and employees of the former Santa Fe Energy Resources,
Inc., not those of the former Snyder Oil Corporation. Therefore, the costs were
required to be expensed as opposed to capitalized as part of the Snyder merger.
Approximately $13.1 million of expenses were incurred in 1998 in
connection with the Northstar combination. These expenses consisted primarily of
investment bankers' fees, legal fees and costs of printing and distributing the
proxy statement to shareholders. The pooling-of-interests method of accounting
for business combinations requires such costs to be expensed as opposed to
capitalized as costs of the transaction.
INTEREST EXPENSE 1999 VS. 1998 Interest expense increased $66.1 million
in 1999. An increase in the average debt balance outstanding from $588.3 million
in 1998 to $1.5 billion in 1999 caused interest expense to increase by $69.9
million. The average interest rate on outstanding debt decreased from 7.3% in
1998 to 7.0% in 1999. This rate decrease caused interest expense to decrease
$4.9 million in 1999. Other items included in interest expense that are not
related to the debt balance outstanding, such as facility and agency fees,
amortization of costs and other miscellaneous items, were $1.1 million higher in
1999 compared to 1998.
Page 15 of 79 pages
<PAGE> 16
1998 VS. 1997 Interest expense increased $2.0 million, or 5%, in 1998.
The average debt balance increased from $461.2 million in 1997 to $588.3 million
in 1998. This increase in the debt outstanding caused interest expense to
increase $10.2 million. The average interest rate decreased from 8.0% in 1997 to
7.3% in 1998. The decrease in 1998's average rate caused a $4.0 million decrease
in interest expense. Interest expense in 1998 also decreased due to the fact
that 1997's interest expense included a $3.3 million "make-whole" payment
related to the early retirement of debt. Other items included in interest
expense that are not related to the balance of debt outstanding, such as
facility and agency fees, amortization of costs and other miscellaneous items,
were $0.9 million lower in 1998 compared to 1997.
DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATE ON
SUBSIDIARY'S LONG-TERM DEBT Prior to January 2000, Northstar had certain fixed
rate senior notes which were denominated in U.S. dollars. Changes in the
exchange rate between the U.S. dollar and the Canadian dollar from the dates the
notes were issued to the dates of repayment increased or decreased the expected
amount of Canadian dollars eventually required to repay the notes. Such changes
in the Canadian dollar equivalent balance of the debt are required to be
included in determining net earnings for the period in which the exchange rate
changes. In mid-January 2000, the U.S. dollar denominated notes were retired
prior to maturity with cash on hand and borrowings under Devon's long-term
credit facilities.
1999 VS. 1998 The rate of converting Canadian dollars to U.S. dollars
increased from $0.6535 at the end of 1998 to $0.6929 at the end of 1999. The
balance of Northstar's U.S. dollar denominated notes remained constant at $225
million throughout 1999. The higher conversion rate on the $225 million of debt
reduced the Canadian dollar equivalent of debt recorded by Northstar at the end
of 1999. Therefore, a $13.2 million reduction to expenses was recorded in 1999.
1998 VS. 1997 The principal balance of Northstar's U.S. dollar
denominated notes increased from $135 million at the end of 1997 to $225 million
at the end of 1998. The rate of converting Canadian dollars to U.S. dollars
decreased from $0.6997 at the end of 1997 to $0.6535 at the end of 1998. The
combination of these factors caused $16.1 million to be recorded as an expense
in 1998.
DISTRIBUTIONS ON PREFERRED SECURITIES OF SUBSIDIARY TRUST As discussed
in Note 9 to the consolidated financial statements included elsewhere herein,
Devon, through its affiliate Devon Financing Trust, completed the issuance of
$149.5 million of 6.5% Trust Convertible Preferred Securities ("TCP Securities")
in July 1996. The TCP Securities had a maturity date of June 15, 2026. However,
in October 1999, Devon issued notice to the holders of the TCP Securities that
it was exercising its right to redeem such securities on November 30, 1999.
Substantially all of the holders of the TCP Securities elected to exercise their
conversion rights instead of receiving the redemption cash value. As a result,
all but 950 of the 2.99 million units of TCP Securities were exchanged for
shares of Devon common stock. As a result, Devon issued approximately 4.9
million shares of common stock for substantially all of the outstanding units of
TCP Securities. The redemption price for the 950 units redeemed was
approximately $50,000.
1999 VS. 1998 The TCP Securities distributions in 1999 were $6.9
million compared to $9.7 million in 1998. Substantially all of the TCP
Securities were exchanged for shares of Devon common stock on November 30, 1999.
Therefore, there was no fourth quarter 1999 distribution on the exchanged TCP
Securities.
1998 VS. 1997 Distributions on the TCP Securities were $9.7 million in
both 1998 and 1997.
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES Under the full
cost method of accounting, the net book value of oil and gas properties, less
related deferred income taxes, may not exceed a calculated "ceiling." The
ceiling limitation is the discounted estimated after-tax future net revenues
from proved oil and gas properties. The ceiling is imposed separately by
country. In calculating future net revenues, current prices and costs are
generally held constant indefinitely. The net book value, less deferred tax
liabilities, is compared to the ceiling on a quarterly and annual basis. Any
excess of the net book value, less deferred taxes, is written off as an expense.
Page 16 of 79 pages
<PAGE> 17
During 1999, 1998 and 1997, Devon reduced the carrying value of its oil
and gas properties by $476.1 million, $422.5 million and $641.3 million,
respectively, due to the full cost ceiling limitations. The after-tax effect of
these reductions in 1999, 1998 and 1997 were $309.7 million, $280.8 million and
$408.2 million, respectively.
INCOME TAXES 1999 VS. 1998 Devon's 1999 financial tax benefit rate was
25% of loss before income tax benefit. This rate was lower than the statutory
federal tax rate of 35% due to the effect of goodwill amortization that is not
deductible for income tax purposes and the effect of foreign income taxes. The
1998 financial tax benefit rate was 35%.
1998 VS. 1997 The 1998 financial tax benefit rate was 35%. The 1997
financial tax benefit rate was 37%. This rate was higher than the statutory
federal tax rate of 35% primarily due to the effect of foreign income taxes.
CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY
The following discussion of capital expenditures, capital resources and
liquidity should be read in conjunction with the supplemental consolidated
statements of cash flows included elsewhere in this report.
CAPITAL EXPENDITURES Approximately $883.4 million was spent in 1999 for
capital expenditures, of which $784.9 million was related to the acquisition,
drilling or development of oil and gas properties and $69.3 million was spent on
the gas gathering and processing project in Wyoming. These amounts compare to
1998 total expenditures of $712.8 million ($704.6 million of which was related
to oil and gas properties) and 1997 total expenditures of $726.9 million ($713.7
million of which was related to oil and gas properties.)
OTHER CASH USES Devon's common stock dividends were $12.7 million, $7.3
million and $6.4 million in 1999, 1998 and 1997, respectively. Devon also paid
$3.7 million of preferred stock dividends in the last 4 1/2 months of 1999
following the PennzEnergy merger and $8.5 million of such dividends in 1997.
CAPITAL RESOURCES AND LIQUIDITY Net cash provided by operating
activities ("operating cash flow") has historically been the primary source of
Devon's capital and short-term liquidity. Operating cash flow was $532.3
million, $334.5 million and $530.2 million in 1999, 1998 and 1997, respectively.
The trends in operating cash flow during these periods have generally followed
those of the various revenue and expense items previously discussed.
In addition to operating cash flow, Devon's credit lines and the
private placement of long-term debt have been an important source of capital and
liquidity. In 1999, debt repayments exceeded borrowings by $144.7 million.
During the years 1998 and 1997, long-term debt borrowings exceeded repayments by
$264.2 million and $245.4 million, respectively.
Prior to the August 2000 merger, Devon and Santa Fe Snyder each had
their own unsecured credit facilities under which a combined total of $645.1
million was borrowed as of December 31, 1999. Devon's credit facilities prior to
the merger aggregated $750 million, with $475 million in a U.S. facility and
$275 million in a Canadian facility. These Devon credit facilities were entered
into in October 1999. Santa Fe Snyder's credit facilities prior to the merger
aggregated $600 million.
Concurrent with the closing of the Santa Fe Snyder merger on August 29,
2000, Devon entered into new unsecured long-term credit facilities aggregating
$1 billion (the "Credit Facilities"). The Credit Facilities replaced the prior
separate facilities of Devon and Santa Fe Snyder. The Credit Facilities include
a U.S. facility of $725 million (the "U.S. Facility") and a Canadian facility of
$275 million (the "Canadian Facility").
The $725 million U.S. Facility consists of a Tranche A facility of $200
million and a Tranche B facility of $525 million. The Tranche B facility can be
increased to as high as $625 million and reduced to as low as $425 million by
reallocating the amount available between the Tranche B facility and the
Canadian Facility. The Tranche A facility matures on October 15, 2004. Devon may
borrow funds under the Tranche B facility until August 28, 2001 (the "Tranche B
Revolving Period"). Devon may request that the Tranche B Revolving Period be
extended an additional 364 days by notifying the agent bank of such request
between 30 and 60 days prior to the end of the Tranche B Revolving Period. Debt
borrowed under the Tranche B facility matures two years and one day following
the end of the Tranche B Revolving Period.
Page 17 of 79 pages
<PAGE> 18
Devon may borrow funds under the $275 million Canadian Facility until
August 28, 2001 (the "Canadian Facility Revolving Period"). As disclosed in the
prior paragraph, the Canadian Facility can be increased to as high as $375
million and reduced to as low as $175 million by reallocating the amount
available between the Tranche B facility and the Canadian Facility. Devon may
request that the Canadian Facility Revolving Period be extended an additional
364 days by notifying the agent bank of such request between 45 and 90 days
prior to the end of the Canadian Facility Revolving Period. Debt outstanding as
of the end of the Canadian Facility Revolving Period is payable in semi-annual
installments of 2.5% each for the following five years, with the final
installment due five years and one day following the end of the Canadian
Facility Revolving Period.
Amounts borrowed under the Credit Facilities bear interest at various
fixed rate options that Devon may elect for periods up to six months. Such rates
are generally less than the prime rate, and are tied to margins determined by
Devon's corporate credit ratings. Devon may also elect to borrow at the prime
rate. The Credit Facilities provide for an annual facility fee of $0.9 million
that is payable quarterly.
Another significant source of liquidity in 1999 was the $402 million
received from the sale of approximately 10.3 million shares of Devon's common
stock in a public offering. The proceeds were primarily used to retire $350
million of long-term debt in the fourth quarter of 1999. The retired debt, which
Devon assumed in the PennzEnergy merger, had an average interest rate of 10% per
year. Also, Santa Fe Snyder raised $108 million in 1999 from an equity offering
of its common stock following its merger with Snyder.
YEAR 2000 STATUS
Devon's company-wide Year 2000 Project ("the Project") was completed on
schedule. The Project addressed the "Year 2000" issue caused by computer
programs being written utilizing two digits rather than four to define an
applicable year. Total costs related to the Project were approximately $3.0
million, of which $1.5 million related to capital items and $1.5 million to
expense items.
During the rollover from December 31, 1999 to January 1, 2000, Devon
followed a Year 2000 rollover plan for reporting, documenting and remediating
Year 2000 errors. These plans included such tasks as on-site testing and
verification of systems at January 1, 2000. Currently, there have been no
business-critical failures reported due to Year 2000 errors. However, there were
two failures reported for non-critical systems, both of which were remedied by
vendor-supplied corrections by January 4, 2000.
Devon will continue to monitor systems for errors due to Year 2000
failures through the processing of leap year related data. Devon does not expect
to incur significant operational problems due to the Year 2000 issue. However,
if all Year 2000 issues are not properly and timely identified, assessed,
remediated and tested, there can be no assurances that the Year 2000 issue will
not materially impact Devon's results of operations or adversely affect its
relationships with customers, vendors, or others. Additionally, there can be no
assurance that the Year 2000 issues of other entities will not have a material
impact on Devon's systems or results of operations.
IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED In June
1998, the Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133"), and in June 2000 issued SFAS 138, which amended
certain provisions of SFAS 133. SFAS 133, as amended, establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. It requires
the recognition of all derivatives as either assets or liabilities in the
statement of financial position and measurement of those instruments at fair
value. If certain conditions are met, a derivative may be specifically
designated as a hedge. The accounting for changes in the fair value of a
derivative (that is gains and losses) depends on the intended use of the
derivative and whether it qualifies as a hedge. A subsequent pronouncement, SFAS
137, was issued in July, 1999 that delayed the effective date of SFAS 133 until
fiscal years beginning after June 15, 2000. Devon plans to adopt the provision
of SFAS 133, as amended, in the first quarter of the year ending December 31,
2001, and is currently evaluating the effects of this pronouncement.
Page 18 of 79 pages
<PAGE> 19
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about Devon's potential
exposure to market risks. The term "market risk" refers to the risk of loss
arising from adverse changes in oil and gas prices, interest rates and foreign
currency exchange rates. The disclosures are not meant to be precise indicators
of expected future losses, but rather indicators of reasonably possible losses.
This forward-looking information provides indicators of how Devon views and
manages its ongoing market risk exposures. All of Devon's market risk sensitive
instruments were entered into for purposes other than trading.
COMMODITY PRICE RISK Devon's major market risk exposure is in the
pricing applicable to its oil and gas production. Realized pricing is primarily
driven by the prevailing worldwide price for crude oil and spot market prices
applicable to its U.S. and Canadian natural gas production. Pricing for oil and
gas production has been volatile and unpredictable for several years.
Devon periodically enters into financial hedging activities with
respect to a portion of its projected oil and natural gas production through
financial price swaps whereby Devon will receive a fixed price for its
production and pay a variable market price to the contract counterparty. These
financial hedging activities are intended to support oil and natural gas prices
at targeted levels and to manage Devon's exposure to oil and gas price
fluctuations. Realized gains or losses from the settlement of these financial
hedging instruments are recognized in oil and gas sales when the associated
production occurs. The gains and losses realized as a result of these hedging
activities are substantially offset in the cash market when the hedged commodity
is delivered. Devon does not hold or issue derivative instruments for trading
purposes.
As of year-end 1999, Devon had financial gas price hedging instruments
in place which represented approximately 18 Bcf, 13 Bcf and 3 Bcf of gas
production in the years 2000, 2001 and 2002, respectively. Also, as of year-end
1999, Devon had various "price collars" in effect for 11,700 barrels of oil
production per day in the year 2000.
Devon uses a sensitivity analysis technique to evaluate the
hypothetical effect that changes in the market value of oil and gas may have on
the fair value of its commodity hedging instruments. At December 31, 1999, a 10%
increase in the underlying commodities' prices would have reduced the fair value
of Devon's commodity hedging instruments by $7.7 million.
In addition to the commodity hedging instruments described above, Devon
also manages its exposure to gas price risks by periodically entering into
fixed-price gas contracts. All of Devon's existing fixed-price contracts relate
to its Canadian gas production. For each of the years of 2000 through 2004,
Devon's fixed-price gas contracts cover approximately 17 Bcf, 12 Bcf, 10 Bcf, 6
Bcf and 6 Bcf of production, respectively. Devon also has Canadian gas volumes
subject to fixed-price contracts in the years from 2005 through 2016, but the
yearly volumes are less than 6 Bcf.
In addition to the fixed-price gas contracts, Devon also entered into
two fixed-price oil sales agreements; one in August 1999 and another in January
2000. Combined, these two agreements fixed the price on approximately 311,000
barrels per month of oil production through August 2002.
INTEREST RATE RISK At December 31, 1999, Devon had long-term debt
outstanding of $2.42 billion. Of this amount, $1.77 billion, or 73%, bears
interest at fixed rates averaging 7.1%. The remaining $0.65 billion of debt
outstanding at the end of 1999 bears interest at floating rates which averaged
6.8% at the end of 1999.
In mid-January 2000, Devon utilized $75 million of cash on hand and
$150 million of borrowings from its long-term credit facilities, which bear
interest at floating rates, to retire $225 million of fixed-rate long-term debt.
This fixed-rate debt retired had an average interest rate of 6.8% per year. Also
in mid-January 2000, Devon used approximately $50 million of cash on hand to
reduce year-end 1999 borrowings under its credit facilities. These early 2000
transactions left Devon with $2.29 billion of total long-term debt, of which
$1.55 billion, or 67%, bears interest at fixed rates averaging 7.2%. The
remaining $0.74 billion of floating-rate debt borrowed under the credit
facilities bears interest, as of January 21, 2000, at an average rate of 6.7%.
Page 19 of 79 pages
<PAGE> 20
The terms of the credit facilities in place allow interest rates to be
fixed at Devon's option for periods of between 30 to 180 days. A 10% increase in
short-term interest rates on the floating-rate debt outstanding as of January
21, 2000, would equal approximately 67 basis points. Such an increase in
interest rates would increase Devon's 2000 interest expense by approximately
$4.9 million assuming borrowed amounts remain outstanding.
The above sensitivity analysis for interest rate risk excludes accounts
receivable, accounts payable and accrued liabilities because of the short-term
maturity of such instruments.
FOREIGN CURRENCY RISK Devon's net assets, net earnings and cash flows
from its Canadian subsidiaries are based on the U.S. dollar equivalent of such
amounts measured in the applicable functional currency. Assets and liabilities
of the Canadian subsidiaries are translated to U.S. dollars using the applicable
exchange rate as of the end of a reporting period. Revenues, expenses and cash
flow are translated using the average exchange rate during the reporting period.
Substantially all of Devon's Canadian oil sales are paid in Canadian
dollars, but at amounts based on the U.S. dollar price of oil. Therefore,
currency fluctuations between the Canadian and U.S. dollars impact the amount of
Canadian dollars received by Devon's Canadian subsidiaries for their oil
production. To mitigate the effect of volatility in the Canadian-to-U.S. dollar
exchange rate on Canadian oil revenues, Devon has existing foreign currency
exchange rate swaps. Under such swap agreements, in 2000 Devon will sell $30
million at an average Canadian-to-U.S. exchange rate of $0.7265 and buy the same
amount of dollars at the floating exchange rate. The amount of gains or losses
realized from such swaps are included as increases or decreases to realized oil
sales. At the year-end 1999 exchange rate, these swaps would result in decreases
to 2000's annual oil sales of approximately $1.4 million. A further $0.03
decrease in the Canadian-to-U.S. dollar exchange rate in 2000 would result in an
additional decrease in oil sales of approximately $1.3 million.
For purposes of the sensitivity analysis described above for changes in
the Canadian dollar exchange rate, a change in the rate of $0.03 was used as
opposed to a 10% change in the rate. During the last seven years, the
Canadian-to-U.S. dollar exchange rate has fluctuated an average of approximately
4% per year, and no year's fluctuation was greater than 7%. The $0.03 change
used in the above analysis represents an approximate 4% change in the year-end
1999 rate.
Page 20 of 79 pages
<PAGE> 21
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Devon Energy Corporation:
We have audited the accompanying supplemental consolidated balance sheets of
Devon Energy Corporation and subsidiaries as of December 31, 1999 and 1998, and
the related supplemental consolidated statements of operations, stockholders'
equity, and cash flows for each of the years in the three-year period ended
December 31, 1999. These supplemental consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these supplemental consolidated financial statements based on our
audits. We did not audit the 1999, 1998 and 1997 financial statements of Santa
Fe Snyder Corporation, a wholly-owned subsidiary, which statements reflect total
assets constituting 24% and 38% in 1999 and 1998, respectively, of the related
consolidated totals, and which statements reflect total revenues constituting
41%, 43% and 50% in 1999, 1998 and 1997, respectively, of the related
consolidated totals. We did not audit the 1998 and 1997 financial statements of
Northstar Energy Corporation, a wholly-owned subsidiary, which statements
reflect total assets constituting 20% of the related consolidated 1998 total,
and which statements reflect total revenues constituting 22% and 19% in 1998 and
1997, respectively, of the related consolidated totals. The 1999, 1998 and 1997
financial statements of Santa Fe Snyder Corporation and the 1998 and 1997
financial statements of Northstar Energy Corporation were audited by other
auditors whose reports have been furnished to us, and our opinion, insofar as it
relates to the amounts included for Santa Fe Snyder Corporation in 1999, 1998
and 1997, and Northstar Energy Corporation in 1998 and 1997, is based solely on
the reports of the other auditors.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits and the reports of
the other auditors provide a reasonable basis for our opinion.
The supplemental consolidated financial statements give retroactive effect to
the merger of Devon Energy Corporation and Santa Fe Snyder Corporation on August
29, 2000, which has been accounted for as a pooling-of-interests as described in
Note 2 to the supplemental consolidated financial statements. Accounting
principles generally accepted in the United States of America proscribe giving
effect to a consummated business combination accounted for by the
pooling-of-interests method in financial statements that do not include the date
of consummation. These financial statements do not extend through the date of
consummation. However, they will become the historical consolidated financial
statements of Devon Energy Corporation and subsidiaries after financial
statements covering the date of consummation of the business combination are
issued.
In our opinion, based on our audits and the reports of the other auditors, the
supplemental consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Devon Energy Corporation and
subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States of America applicable after financial statements
are issued for a period which includes the date of consummation of the business
combination.
KPMG LLP
Oklahoma City, Oklahoma
November 8, 2000
Page 21 of 79 pages
<PAGE> 22
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of
Devon Energy Corporation:
We have audited the consolidated balance sheet of Santa Fe Snyder Corporation (a
wholly owned subsidiary of Devon Energy Corporation) as of December 31, 1999 and
1998, and the related consolidated statements of operations, comprehensive
income, shareholders' equity and of cash flows for each of the three years in
the period ended December 31, 1999 (not separately included herein). These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Santa Fe Snyder
Corporation at December 31, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999 in conformity with accounting principles generally accepted in the
United States of America.
As further described in Note 2, these consolidated financial statements have
been retroactively restated to the full cost method of accounting for the
Company's oil and gas properties in order to conform to the accounting policies
of Devon Energy Corporation.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas
January 28, 2000, except for Note 2 and the fourth paragraph
above which are as of October 30, 2000
Page 22 of 79 pages
<PAGE> 23
AUDITORS' REPORT TO THE SHAREHOLDERS
We have audited the consolidated balance sheet of Northstar Energy Corporation
(a wholly owned subsidiary of Devon Energy Corporation) as at December 31, 1998
and the related consolidated statements of operations and comprehensive income
(loss), stockholders' equity and cash flows for each of the years in the
two-year period ended December 31, 1998 (not separately included herein). These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards, which are substantially similar to generally accepted auditing
standards in the United States. Those standards require that we plan and perform
an audit to obtain reasonable assurance whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31,
1998, and the results of its operations and the changes in its cash flow for
each of the years in the two-year period ended December 31, 1998 in accordance
with generally accepted accounting principles in the United States.
/s/ DELOITTE & TOUCHE LLP
-------------------------
Deloitte & Touche LLP
Chartered Accountants
Calgary, Alberta
Canada
January 20, 1999
Page 23 of 79 pages
<PAGE> 24
DEVON ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1999 1998
----------- -----------
ASSETS
Current assets:
<S> <C> <C>
Cash and cash equivalents $ 173,167 31,254
Accounts receivable 316,005 137,058
Inventories 38,941 21,750
Assets held for sale -- --
Deferred income taxes 4,886 605
Investments and other current assets 57,295 35,981
----------- -----------
Total current assets 590,294 226,648
----------- -----------
Property and equipment, at cost, based on the full
cost method of accounting for oil and gas properties 8,592,010 4,854,211
Less accumulated depreciation, depletion and
amortization 4,168,590 3,230,683
----------- -----------
4,423,420 1,623,528
Investment in Chevron Corporation common stock,
at fair value 614,382 --
Deferred income taxes -- 54,381
Goodwill, net of amortization 322,800 --
Other assets 145,464 25,980
----------- -----------
Total assets $ 6,096,360 1,930,537
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade 266,825 155,377
Revenues and royalties due to others 67,330 20,608
Income taxes payable 12,587 1,200
Current portion of long-term debt -- --
Accrued interest payable 28,370 5,588
Merger related expenses payable 35,704 7,882
Accrued expenses 56,528 29,201
----------- -----------
Total current liabilities 467,344 219,856
----------- -----------
Other liabilities 262,310 71,947
Debentures exchangeable into shares of Chevron
Corporation common stock 760,313 --
Other long-term debt 1,656,208 735,871
Deferred revenue 104,800 3,600
Deferred income taxes 324,065 --
Company-obligated mandatorily redeemable convertible
preferred securities of subsidiary trust holding
solely 6.5% convertible junior subordinated
debentures of Devon Energy Corporation -- 149,500
Stockholders' equity:
Preferred stock of $1.00 par value ($100 liquidation value) Authorized
4,500,000 shares; issued 1,500,000
in 1999 and none in 1998 1,500 --
Common stock of $.10 par value
Authorized 400,000,000 shares; issued 126,323,000
in 1999 and 70,909,000 in 1998 12,632 7,090
Additional paid-in capital 3,491,828 1,523,944
Retained earnings (accumulated deficit) (908,598) (737,009)
Accumulated other comprehensive loss (65,242) (35,962)
Unamortized restricted stock awards -- (1,500)
Treasury stock, at cost: 330,000 shares in 1999 and 176,000 shares in 1998 (10,800) (6,800)
----------- -----------
Total stockholders' equity 2,521,320 749,763
----------- -----------
Commitments and contingencies (Notes 12 and 13)
Total liabilities and stockholders' equity $ 6,096,360 1,930,537
=========== ===========
</TABLE>
See accompanying notes to supplemental consolidated financial statements
Page 24 of 79 pages
<PAGE> 25
DEVON ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1999 1998 1997
----------- ----------- -----------
REVENUES
<S> <C> <C> <C>
Oil sales $ 553,834 306,924 552,525
Gas sales 603,225 328,444 357,559
Natural gas liquids sales 67,944 24,692 35,820
Other 20,596 24,248 48,255
----------- ----------- -----------
Total revenues 1,245,599 684,308 994,159
----------- ----------- -----------
COSTS AND EXPENSES
Lease operating expenses 303,248 229,884 266,197
Production taxes 42,355 22,816 31,027
Depreciation, depletion and amortization of property
and equipment 406,375 243,144 285,708
Amortization of goodwill 16,111 -- --
General and administrative expenses 80,645 45,454 53,081
Expenses related to mergers 16,800 13,149 --
Interest expense 109,613 43,532 41,488
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt (13,154) 16,104 5,860
Distributions on preferred securities of
subsidiary trust 6,884 9,717 9,717
Reduction of carrying value of oil and gas properties 476,100 422,500 641,314
----------- ----------- -----------
Total costs and expenses 1,444,977 1,046,300 1,334,392
----------- ----------- -----------
Earnings (loss) before income tax expense (benefit), minority
interest and extraordinary item (199,378) (361,992) (340,233)
INCOME TAX EXPENSE (BENEFIT)
Current 23,056 (3,713) 35,757
Deferred (72,490) (122,394) (162,499)
----------- ----------- -----------
Total income tax expense (benefit) (49,434) (126,107) (126,742)
----------- ----------- -----------
Earnings (loss) before minority interest and (149,944) (235,885) (213,491)
extraordinary item
Minority interest in Monterey Resources, Inc. -- -- (4,700)
----------- ----------- -----------
Earnings (loss) before extraordinary item (149,944) (235,885) (218,191)
Extraordinary loss (4,200) -- --
----------- ----------- -----------
Net earnings (loss) (154,144) (235,885) (218,191)
Preferred stock dividends 3,651 -- 12,000
----------- ----------- -----------
Net earnings (loss) applicable to common shareholders $ (157,795) (235,885) (230,191)
=========== =========== ===========
Net earnings (loss) per average common share outstanding:
Before extraordinary loss - basic and diluted $ (1.64) (3.32) (3.35)
=========== =========== ===========
After extraordinary loss - basic and diluted $ (1.68) (3.32) (3.35)
=========== =========== ===========
Weighted average common shares
outstanding - basic 93,653 70,948 68,732
=========== =========== ===========
</TABLE>
See accompanying notes to supplemental consolidated financial statements.
Page 25 of 79 pages
<PAGE> 26
DEVON ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
RETAINED
EARNINGS
ADDITIONAL (ACCUMU-
PREFERRED COMMON PAID-IN LATED
STOCK STOCK CAPITAL DEFICIT)
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Balance as of December 31, 1996 $ 91,400 6,290 1,156,247 (81,210)
Comprehensive loss:
Net loss -- -- -- (218,191)
Other comprehensive loss - foreign
currency translation adjustments -- -- -- --
Comprehensive loss -- -- -- --
Stock issued -- 1,173 460,895 --
Conversion to common stock (91,400) 100 119,300 (8,400)
Stock repurchased -- (486) (216,514) --
Tax benefit related to employee -- -- 1,200 --
stock options
Dividends on common stock -- -- -- (6,445)
Dividends on preferred stock -- -- -- (3,600)
Spin-off of Monterey Resources, Inc. -- -- -- (175,400)
Amortization of restricted stock awards -- -- -- --
------------ ------------ ------------ ------------
Balance as of December 31, 1997 -- 7,077 1,521,128 (493,246)
Comprehensive loss:
Net loss -- -- -- (235,885)
Other comprehensive loss, net of tax:
Foreign currency translation adjustments -- -- -- --
Minimum pension liability adjustment -- -- -- --
Other comprehensive loss -- -- -- --
Comprehensive loss -- -- -- --
Stock issued -- 13 2,816 (600)
Stock repurchased -- -- -- --
Dividends on common stock -- -- -- (7,278)
Amortization of restricted stock awards -- -- -- --
------------ ------------ ------------ ------------
Balance as of December 31, 1998 -- 7,090 1,523,944 (737,009)
Comprehensive loss:
Net loss -- -- -- (154,144)
Other comprehensive loss, net of tax:
Foreign currency translation adjustments -- -- -- --
Minimum pension liability adjustment -- -- -- --
Unrealized losses on marketable securities -- -- -- --
Other comprehensive loss -- -- -- --
Comprehensive loss -- -- -- --
Stock issued 1,500 5,542 1,966,930 (1,100)
Stock repurchased -- -- -- --
Tax benefit related to employee -- -- 954 --
stock options
Dividends on common stock -- -- -- (12,694)
Dividends on preferred stock -- -- -- (3,651)
Amortization of restricted stock awards -- -- -- --
------------ ------------ ------------ ------------
Balance as of December 31, 1999 $ 1,500 12,632 3,491,828 (908,598)
============ ============ ============ ============
<CAPTION>
ACCUMU-
LATED
OTHER UNAMORTIZED TOTAL
COMPRE- RESTRICTED STOCK-
HENSIVE STOCK TREASURY HOLDERS'
LOSS AWARDS STOCK EQUITY
----------- ------------ ------------ ------------
<S> <C> <C> <C> <C>
Balance as of December 31, 1996 (12,655) -- (300) 1,159,772
Comprehensive loss:
Net loss -- -- -- (218,191)
Other comprehensive loss - foreign
currency translation adjustments (14,458) -- -- (14,458)
Comprehensive loss -- -- -- (232,649)
Stock issued -- (2,400) 200 459,868
Conversion to common stock -- -- -- 19,600
Stock repurchased -- -- (500) (217,500)
Tax benefit related to employee -- -- -- 1,200
stock options
Dividends on common stock -- -- -- (6,445)
Dividends on preferred stock -- -- -- (3,600)
Spin-off of Monterey Resources, Inc. -- -- -- (175,400)
Amortization of restricted stock awards -- 1,700 -- 1,700
----------- ------------ ------------ ------------
Balance as of December 31, 1997 (27,113) (700) (600) 1,006,546
Comprehensive loss:
Net loss -- -- -- (235,885)
Other comprehensive loss, net of tax:
Foreign currency translation adjustments (8,130) -- -- (8,130)
Minimum pension liability adjustment (719) -- -- (719)
Other comprehensive loss -- -- -- (8,849)
Comprehensive loss -- -- -- (244,734)
Stock issued -- (2,600) 5,400 5,029
Stock repurchased -- -- (11,600) (11,600)
Dividends on common stock -- -- -- (7,278)
Amortization of restricted stock awards -- 1,800 -- 1,800
----------- ------------ ------------ ------------
Balance as of December 31, 1998 (35,962) (1,500) (6,800) 749,763
Comprehensive loss:
Net loss -- -- -- (154,144)
Other comprehensive loss, net of tax:
Foreign currency translation adjustments 7,517 -- -- 7,517
Minimum pension liability adjustment (241) -- -- (241)
Unrealized losses on marketable securities (36,556) -- -- (36,556)
Other comprehensive loss -- -- -- (29,280)
------------
Comprehensive loss -- -- -- (183,424)
Stock issued -- (100) 7,600 1,980,372
Stock repurchased -- -- (11,600) (11,600)
Tax benefit related to employee -- -- -- 954
stock options
Dividends on common stock -- -- -- (12,694)
Dividends on preferred stock -- -- -- (3,651)
Amortization of restricted stock awards -- 1,600 -- 1,600
----------- ------------ ------------ ------------
Balance as of December 31, 1999 (65,242) -- (10,800) 2,521,320
=========== ============ ============ ============
</TABLE>
See accompanying notes to supplemental consolidated financial statements.
Page 26 of 79 pages
<PAGE> 27
DEVON ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net earnings (loss) $ (154,144) (235,885) (218,191)
Adjustments to reconcile net earnings (loss) to net cash provided by
operating activities:
Depreciation, depletion and amortization of property
and equipment 406,375 243,144 285,708
Amortization of goodwill 16,111 -- --
Amortization of discounts (premiums) on debentures, net (728) 100 100
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt (13,154) 16,104 5,860
Reduction of carrying value of oil and gas properties 476,100 422,500 641,314
Gain on sale of assets 4,778 (264) (29,673)
Deferred income taxes (benefit) (72,490) (122,394) (162,499)
Other 2,100 4,801 13,364
Changes in assets and liabilities, net of effects of acquisitions of
businesses:
(Increase) decrease in:
Accounts receivable (92,416) 30,760 (6,104)
Inventories (8,514) (1,427) (2,102)
Prepaid expenses (4,418) (7,751) 5,970
Other assets (36,673) 17,230 8,226
(Decrease) increase in:
Accounts payable (22,495) (19,439) 15,600
Income taxes payable (19,318) (10,426) (14,731)
Accrued expenses (38,387) 1,000 (14,268)
Deferred revenue 90,700 (100) (300)
Long-term other liabilities (1,099) (3,482) 1,882
----------- ----------- -----------
Net cash provided by operating activities 532,328 334,471 530,156
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of property and equipment 114,384 64,997 221,096
Proceeds from sale of investments -- 42,584 --
Capital expenditures (883,420) (712,812) (726,891)
Increase in equity investment -- -- (32,428)
Decrease (increase) in other assets 719 (2,029) (7,460)
----------- ----------- -----------
Net cash used in investing activities (768,317) (607,260) (545,683)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings on long-term debt 1,944,417 1,506,220 950,785
Principal payments on long-term debt (2,089,109) (1,242,013) (705,427)
Issuance of common stock, net of issuance costs 530,232 4,429 15,678
Retirement of preferred securities of subsidiary trust (50) -- --
Repurchase of common stock (11,600) (11,600) (217,500)
Issuance of treasury stock 6,200 --
Dividends paid on common stock (12,694) (7,278) (6,445)
Dividends paid on preferred stock (3,651) -- (8,500)
Increase in long-term other liabilities 13,453 6,760 6,268
----------- ----------- -----------
Net cash provided by financing activities 377,198 256,518 34,859
----------- ----------- -----------
Effect of exchange rate changes on cash 704 (140) 316
----------- ----------- -----------
Net increase (decrease) in cash and cash equivalents 141,913 (16,411) 19,648
Cash and cash equivalents at beginning of year 31,254 47,665 28,017
----------- ----------- -----------
Cash and cash equivalents at end of year $ 173,167 31,254 47,665
=========== =========== ===========
</TABLE>
See accompanying notes to supplemental consolidated financial statements.
Page 27 of 79 pages
<PAGE> 28
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting policies used by Devon Energy Corporation and subsidiaries
("Devon") reflect industry practices and conform to accounting principles
generally accepted in the United States of America. The more significant of such
policies are briefly discussed below.
Basis of Presentation and Principles of Consolidation
Devon is engaged primarily in oil and gas exploration, development and
production, and the acquisition of producing properties. Such activities
domestically are managed in three divisions:
- the Gulf Division, which includes properties located primarily
in the onshore South Texas and South Louisiana areas and
offshore in the Gulf of Mexico;
- the Rocky Mountain Division, which includes properties located
in the Rocky Mountains area of the United States stretching
from the Canadian Border into northern New Mexico; and
- the Permian/Mid-Continent Division, which includes all
domestic properties other than those included in the Gulf
Division and the Rocky Mountain Division.
Devon's Canadian activities are located primarily in the Western
Canadian Sedimentary Basin, and Devon's international activities -- outside of
North America -- are located primarily in Argentina, Azerbaijan, Indonesia,
Gabon and Venezuela. Devon's share of the assets, liabilities, revenues and
expenses of affiliated partnerships and the accounts of its wholly-owned
subsidiaries are included in the accompanying consolidated financial statements.
All significant intercompany accounts and transactions have been eliminated in
consolidation.
Information concerning common stock and per share data assumes the
exchange of all Exchangeable Shares issued in connection with the Northstar
combination described in Note 2.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Actual amounts could differ from those
estimates.
Inventories
Inventories, which consist primarily of injected gas and tubular goods,
parts and supplies, are stated at cost, determined principally by the average
cost method, which is not in excess of net realizable value.
Property and Equipment
Devon follows the full cost method of accounting for its oil and gas
properties. Accordingly, all costs incidental to the acquisition, exploration
and development of oil and gas properties, including costs of undeveloped
leasehold, dry holes and leasehold equipment, are capitalized. Net capitalized
costs are limited to the estimated future net revenues, discounted at 10% per
annum, from proved oil, natural gas and natural gas liquids reserves. Such
limitations are imposed separately on a country-by-country basis. Capitalized
costs are depleted by an equivalent unit-of-production method, converting gas to
oil at the ratio of one barrel of oil to six thousand cubic feet of natural gas.
No gain or loss is recognized upon disposal of oil and gas properties unless
such disposal significantly alters the relationship between capitalized costs
and proved reserves.
Page 28 of 79 pages
<PAGE> 29
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Depreciation and amortization of other property and equipment,
including leasehold improvements, are provided using the straight-line method
based on estimated useful lives from 3 to 39 years.
Marketable Securities and Other Investments
Devon accounts for certain investments in debt and equity securities by
following the requirements of Statement of Financial Accounting Standards
("SFAS") No. 115, "Accounting for Certain Investments in Debt and Equity
Securities." This standard requires that, except for debt securities classified
as "held-to-maturity," investments in debt and equity securities must be
reported at fair value. As a result, Devon's investment in Chevron Corporation
common stock, which is classified as "available for sale," is reported at fair
value, with the tax effected unrealized gain or loss recognized in other
comprehensive earnings (loss) and reported as a separate component of
stockholders' equity. Devon's investments in other short-term securities are
also classified as "available for sale."
Goodwill
Goodwill, which represents the excess of purchase price over the fair
value of net assets acquired, is amortized by an equivalent unit-of-production
method. Devon assesses the recoverability of this intangible asset by
determining whether the amortization of the goodwill balance over its remaining
life can be recovered through undiscounted future operating cash flows of the
acquired properties. The amount of goodwill impairment, if any, is measured
based on projected discounted future operating cash flows using a discount rate
reflecting Devon's average cost of funds. The assessment of the recoverability
of goodwill will be impacted if estimated future operating cash flows are not
achieved.
Accumulated amortization of goodwill was $16.1 million at December 31,
1999.
Revenue Recognition and Gas Balancing
Oil and gas revenues are recognized when produced. During the course of
normal operations, Devon and other joint interest owners of natural gas
reservoirs will take more or less than their respective ownership share of the
natural gas volumes produced. These volumetric imbalances are monitored over the
lives of the wells' production capability. If an imbalance exists at the time
the wells' reserves are depleted, cash settlements are made among the joint
interest owners under a variety of arrangements.
Devon follows the sales method of accounting for gas imbalances. A
liability is recorded when Devon's excess takes of natural gas volumes exceed
its estimated remaining recoverable reserves. No receivables are recorded for
those wells where Devon has taken less than its ownership share of gas
production.
Hedging Activities
Devon has periodically entered into oil and gas price swaps and foreign
exchange rate swaps to manage its exposure to oil and gas price volatility. The
foreign exchange rate swaps mitigate the effect of volatility in the
Canadian-to-U.S. dollar exchange rate on Canadian oil revenues that are
predominantly based on U.S. dollar prices. The hedging instruments are usually
placed with counterparties that Devon believes are minimal credit risks. The oil
and gas reference prices upon which the price hedging instruments are based
reflect various market indices that have a high degree of historical correlation
with actual prices received by Devon.
Devon accounts for its hedging instruments using the deferral method of
accounting. Under this method, realized gains and losses from Devon's price risk
management activities are recognized in oil and gas revenues when the associated
production
Page 29 of 79 pages
<PAGE> 30
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
occurs and the resulting cash flows are reported as cash flows from operating
activities. Gains and losses on hedging contracts that are closed before the
hedged production occurs are deferred until the production month originally
hedged. In the event of a loss of correlation between changes in oil and gas
reference prices under a hedging instrument and actual oil and gas prices, a
gain or loss is recognized currently to the extent the hedging instrument has
not offset changes in actual oil and gas prices.
Stock Options
Devon applies the intrinsic value-based method of accounting prescribed
by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations, in accounting for its fixed plan stock
options. As such, compensation expense would be recorded on the date of grant
only if the current market price of the underlying stock exceeded the exercise
price. SFAS No. 123, "Accounting for Stock-Based Compensation," established
accounting and disclosure requirements using a fair value-based method of
accounting for stock-based employee compensation plans. As allowed by SFAS No.
123, Devon has elected to continue to apply the intrinsic value-based method of
accounting described above, and has adopted the disclosure requirements of SFAS
No. 123 which are included in Note 10.
Major Purchasers
In 1998, Aquila Energy Marketing Corporation accounted for 11% of
Devon's combined oil, gas and natural gas liquids sales. No purchaser accounted
for over 10% of such revenues in 1999 or 1997.
Income Taxes
Devon accounts for income taxes using the asset and liability method,
whereby deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of assets and liabilities and their respective tax bases, as
well as the future tax consequences attributable to the future utilization of
existing tax net operating loss and other types of carryforwards. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those temporary differences and
carryforwards are expected to be recovered or settled. The effect on deferred
tax assets and liabilities of a change in tax rates is recognized in income in
the period that includes the enactment date. U.S. deferred income taxes have not
been provided on Canadian earnings which are being permanently reinvested.
General and Administrative Expenses
General and administrative expenses are reported net of amounts
allocated to working interest owners of the oil and gas properties operated by
Devon and net of amounts capitalized pursuant to the full cost method of
accounting.
Net Earnings Per Common Share
Basic earnings per share is computed by dividing income available to
common stockholders by the weighted average number of common shares outstanding
for the period. Diluted earnings per share reflects the potential dilution that
could occur if Devon's dilutive outstanding stock options were exercised
(calculated using the treasury stock method) or if Devon's Trust Convertible
Preferred Securities were converted to common stock. Substantially all of
Devon's Trust Convertible Preferred Securities were converted to common stock on
November 30, 1999 (see Note 9).
The diluted loss per share calculations for 1999, 1998 and 1997 produce
results that are anti-dilutive. (The diluted calculation for 1999 reduced the
net loss by $4.3 million and increased the common shares outstanding by 5.7
million shares. The diluted calculation for 1998 reduced the net loss by $6.0
million and increased the common shares outstanding by 6.0 million shares. The
1997 diluted calculation reduced the net loss by $18.0 million and increased the
common shares
Page 30 of 79 pages
<PAGE> 31
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
outstanding by 6.6 million shares.) Therefore, the diluted loss per share
amounts for 1999, 1998 and 1997 reported in the accompanying consolidated
statements of operations are the same as the basic loss per share amounts.
Comprehensive Earnings (Loss)
Devon adopted SFAS No. 130, "Reporting Comprehensive Income," on
January 1, 1998. SFAS No. 130 was effective for fiscal years beginning after
December 15, 1997. SFAS No. 130 established standards for reporting and display
of comprehensive income and its components. Devon's comprehensive income
information is included in the accompanying consolidated statements of
stockholders' equity. A summary of accumulated other comprehensive loss as of
December 31, 1999, 1998 and 1997, and changes during each of the years then
ended, is presented in the following table.
<TABLE>
<CAPTION>
FOREIGN MINIMUM
CURRENCY PENSION UNREALIZED
TRANSLATION LIABILITY LOSSES ON
ADJUST- ADJUST- MARKETABLE
MENTS MENTS SECURITIES TOTAL
------------ ------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Balance as of December 31, 1996 $ (12,655) -- -- (12,655)
1997 activity (14,458) -- -- (14,458)
------------ ------------ ------------ ------------
Balance as of December 31, 1997 (27,113) -- -- (27,113)
1998 activity (8,130) (1,179) -- (9,309)
Deferred taxes -- 460 -- 460
------------ ------------ ------------ ------------
1998 activity, net of deferred taxes (8,130) (719) -- (8,849)
------------ ------------ ------------ ------------
Balance as of December 31, 1998 (35,243) (719) -- (35,962)
1999 activity 7,517 (394) (59,959) (52,836)
Deferred taxes -- 153 23,403 23,556
------------ ------------ ------------ ------------
1999 activity, net of deferred taxes 7,517 (241) (36,556) (29,280)
------------ ------------ ------------ ------------
Balance as of December 31, 1999 $ (27,726) (960) (36,556) (65,242)
============ ============ ============ ============
</TABLE>
Foreign Currency Translation Adjustments
The assets and liabilities of certain foreign subsidiaries are prepared
in their respective local currencies and translated into U.S. dollars based on
the current exchange rate in effect at the balance sheet dates, while income and
expenses are translated at average rates for the periods presented. Translation
adjustments have no effect on net income and are included in accumulated other
comprehensive loss.
Dividends
Dividends on Devon's common stock were paid in 1999, 1998 and 1997 at a
per share rate of $0.05 per quarter. As adjusted for the pooling-of-interests
method of accounting followed for the Santa Fe Snyder merger and the Northstar
combination, annual dividends per share for 1999, 1998 and 1997 were $0.14,
$0.10 and $0.09, respectively.
Statements of Cash Flows
For purposes of the consolidated statements of cash flows, Devon
considers all highly liquid investments with original maturities of three months
or less to be cash equivalents.
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments,
litigation or other sources are recorded when it is probable that a liability
has been incurred and the amount can be reasonably estimated.
Page 31 of 79 pages
<PAGE> 32
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Environmental expenditures are expensed or capitalized in accordance
with accounting principles generally accepted in the United States of America.
Liabilities for these expenditures are recorded when it is probable that
obligations have been incurred and the amounts can be reasonably estimated.
Reference is made to Note 13 for a discussion of amounts recorded for these
liabilities.
2. BUSINESS COMBINATIONS AND PRO FORMA INFORMATION
Santa Fe Snyder Merger
Devon closed its merger with Santa Fe Snyder Corporation ("Santa Fe
Snyder") on August 29, 2000. The merger was accounted for using the
pooling-of-interests method of accounting for business combinations.
Accordingly, All operational and financial information contained herein includes
the combined amounts for Devon and Santa Fe Snyder for all periods presented.
Devon issued approximately 40.6 million shares of its common stock to
the former stockholders of Santa Fe Snyder based on an exchange ratio of 0.22
shares of Devon common stock for each share of Santa Fe Snyder common stock.
Because the merger was accounted for using the pooling-of-interests method, all
combined share information has been retroactively restated to reflect the
exchange ratio.
PennzEnergy Merger
Devon closed its merger with PennzEnergy Company ("PennzEnergy") on
August 17, 1999. The merger was accounted for using the purchase method of
accounting for business combinations. Accordingly, the accompanying statement of
operations for 1999 includes the effects of PennzEnergy operations since August
17, 1999.
Devon issued approximately 21.5 million shares of its common stock to
the former stockholders of PennzEnergy. In addition, Devon assumed long-term
debt and other obligations totaling approximately $2.3 billion on August 17,
1999. The calculation of the total purchase price and the preliminary allocation
to assets and liabilities as of August 17, 1999, are shown below. Devon has sold
certain of the assets acquired. Generally, the proceeds from such sales reduced
the carrying value of oil and gas properties.
<TABLE>
<CAPTION>
(IN THOUSANDS,
EXCEPT SHARE PRICE)
<S> <C>
Calculation and preliminary allocation of purchase price:
Shares of Devon common stock issued to PennzEnergy
stockholders 21,501
Average Devon stock price $ 33.40
-----------
Fair value of common stock issued $ 718,177
Plus preferred stock assumed by Devon 150,000
Plus estimated merger costs incurred 71,545
Plus fair value of PennzEnergy employee stock options
assumed by Devon 18,295
Less stock registration and issuance costs incurred (4,985)
-----------
Total purchase price 953,032
Plus fair value of liabilities assumed by Devon:
Current liabilities 200,708
Debentures exchangeable into Chevron Corporation
common stock 760,313
Other long-term debt 838,792
Other long-term liabilities 158,988
-----------
2,911,833
Less fair value of non oil and gas assets acquired by Devon:
Current assets 109,769
Non oil and gas properties 31,412
Investment in common stock of Chevron Corporation 676,441
Other assets 81,945
-----------
Fair value allocated to oil and gas properties, including $83.3
million of undeveloped leasehold $ 2,012,266
===========
</TABLE>
Page 32 of 79 pages
<PAGE> 33
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Additionally, $338.9 million was added as goodwill for deferred taxes
created as a result of the merger. Due to the tax-free nature of the merger,
Devon's tax basis in the assets acquired and liabilities assumed are the same as
PennzEnergy's tax basis. The $338.9 million of deferred taxes recorded represent
the deferred tax effect of the differences between the fair values assigned by
Devon for financial reporting purposes to the former PennzEnergy assets and
liabilities and their bases for income tax purposes.
Estimated proved reserves added in the PennzEnergy merger were 232.7
million barrels of oil, 782.6 billion cubic feet of natural gas and 32.7 million
barrels of natural gas liquids. Also, added in the PennzEnergy merger were
approximately 13 million net acres of undeveloped leasehold. (The quantities of
proved reserves stated in this paragraph are unaudited.)
Snyder Merger
Santa Fe Snyder was formed on May 5, 1999, when the former Santa Fe
Energy Resources, Inc. ("Santa Fe") closed its merger with Snyder Oil
Corporation ("Snyder"). Because Devon's merger with Santa Fe Snyder was
accounted for using the pooling-of-interests method, the accompanying
consolidated financial statements are presented as though Devon merged with
Snyder in May 1999.
The Snyder merger was accounted for using the purchase method of
accounting for business combinations. Accordingly, the accompanying statement of
operations for 1999 includes the effects of Snyder's operations since May 5,
1999.
As restated for the Devon-Santa Fe Snyder pooling, each share of Snyder
common stock was exchanged for 0.451 shares of Devon common stock. This resulted
in the issuance of approximately 15.1 million shares of Devon stock in the
Snyder merger. In addition, the Snyder merger also included the assumption of
approximately $219 million of Snyder's long-term debt as of May 5, 1999. The
calculation of the total purchase price and the allocation to assets and
liabilities as of May 5, 1999, are as follows.
<TABLE>
<CAPTION>
(IN THOUSANDS,
EXCEPT SHARE PRICE)
<S> <C>
Calculation and allocation of purchase price:
Shares of Santa Fe common stock issued to Snyder
Stockholders, as adjusted for the Devon-Santa Fe Snyder pooling 15,130
------------
Average Santa Fe stock price, as adjusted for the Devon-Santa Fe Snyder pooling $ 27.24
------------
Fair value of common stock issued $ 412,092
------------
Plus estimated merger costs incurred 1,485
------------
Total purchase price 413,577
Plus fair value of liabilities assumed:
Current liabilities 55,118
Long-term debt 219,001
Other long-term liabilities 26,254
------------
713,950
Less fair value of non oil and gas assets acquired:
Current assets 16,755
Other assets 37,211
------------
Fair value allocated to oil and gas properties, including $14.7 million
of undeveloped leasehold $ 659,984
============
</TABLE>
Additionally, $135.4 million was added to oil and gas properties for
deferred taxes created as a result of the Snyder merger. Due to the tax-free
nature of the merger, Santa Fe's tax basis in the assets acquired and
liabilities assumed were the same as Snyder's tax basis. The $135.4 million of
deferred taxes recorded represent the deferred tax effect of the differences
between the fair values assigned by Santa Fe for financial reporting purposes to
the former Snyder assets and liabilities and their bases for income tax
purposes.
Page 33 of 79 pages
<PAGE> 34
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Estimated proved reserves added in the Snyder merger were 17.7 million
barrels of oil and natural gas liquids and 424 billion cubic feet of natural
gas. Also added in the Snyder merger were approximately 800,000 net acres of
undeveloped leasehold. (The quantities of proved reserves stated in this
paragraph are unaudited.)
Wascana Properties Transaction
On December 23, 1998, Devon acquired certain natural gas properties
located in northeastern Alberta, Canada, from Wascana Oil and Gas Partnership, a
subsidiary of Canadian Occidental Petroleums Ltd. (the "Wascana Properties").
Devon acquired the properties for approximately $57.5 million, which was funded
with bank debt under Devon's then existing credit facilities.
Estimated proved reserves of the Wascana Properties as of December 31,
1998, were 71.5 billion cubic feet of natural gas. Approximately $52.2 million
of the purchase price was allocated to the proved reserves. The remaining $5.3
million of the purchase price was allocated to approximately 190,000 net
undeveloped acres and exclusive rights to associated seismic data. (The
quantities of proved reserves stated in this paragraph are unaudited.)
Pro Forma Information
Set forth in the following table is certain unaudited pro forma
financial information for the years ended December 31, 1999 and 1998. This
information has been prepared assuming the PennzEnergy merger, the Snyder merger
and the Wascana Property transaction were consummated on January 1, 1998, and is
based on estimates and assumptions deemed appropriate by Devon. The pro forma
information is presented for illustrative purposes only. If the transactions had
occurred in the past, Devon's operating results might have been different from
those presented in the following table. The pro forma information should not be
relied upon as an indication of the operating results that Devon would have
achieved if the transactions had occurred on January 1, 1998. The pro forma
information also should not be used as an indication of the future results that
Devon will achieve after the transactions.
The pro forma information includes the effect of Devon's issuance of
10.3 million shares of common stock as if such shares had been issued on January
1, 1998. (See Note 10 for additional information on this issuance of shares of
common stock.) The pro forma information assumes that the approximately $402
million of net proceeds from the issuance of common stock was used to retire
long-term debt and therefore reduce interest expense.
The following should be considered in connection with the pro forma
financial information presented:
o Expected annual cost savings of $30 to $35 million related to
the Santa Fe Snyder merger and $50 to $60 million related to
the PennzEnergy merger have not been reflected as an
adjustment to the historical data in preparing the following
pro forma information. These cost savings are expected to
result from the consolidation of the corporate headquarters of
Devon, Santa Fe Snyder and PennzEnergy and the elimination of
duplicate staff and expenses. Some of the cost savings related
to the Santa Fe Snyder merger involve items that, under the
full cost method of accounting, are capitalized rather than
expensed in the consolidated financial statements. Therefore,
not all of the $30 to $35 million of expected savings will
result in reductions to expenses as reported in the
accompanying consolidated statements of operations.
o The 1999 pro forma results include a gain of $46.7 million
($29.8 million after-tax) from PennzEnergy's pre-merger sale
of land, timber and mineral rights in Pennsylvania and New
York.
Page 34 of 79 pages
<PAGE> 35
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
o In 1998, PennzEnergy realized pretax gains on the sale and
exchange of Chevron Corporation common stock of $203.1
million. This gain is included in the 1998 pro forma financial
information presented in the following table. The pro forma
financial information does not include the related $207.0
million after-tax extraordinary loss resulting from the early
extinguishment of debt. The exclusion of the extraordinary
loss from the 1998 pro forma results is required by Securities
and Exchange Commission rules and regulations regarding
presentation of pro forma results of operations. If the
extraordinary loss were included in the 1998 pro forma
results, the 1998 pro forma net loss as presented in the
following table would be $508.8 million, or $4.37 per share.
o The 1999 pro forma financial information does not include a
$4.2 million extraordinary loss recorded by Santa Fe Snyder.
This loss related to the early extinguishment of debt. If the
extraordinary loss were included in the 1999 pro forma
results, the 1999 pro forma net loss as presented in the
following table would be $211.9 million, or $1.85 per share.
o The 1998 pro forma results include $24.3 million of
nonrecurring general and administrative expenses in connection
with the spin-off of Pennzoil-Quaker State Company on December
30, 1998.
o The 1999 and 1998 pro forma results include reductions of the
carrying value of oil and gas properties of $476.1 million and
$422.5 million, respectively. The after-tax effect of these
reductions, which were due to the full cost ceiling
limitation, were $309.7 million in 1999 and $280.8 million in
1998.
Page 35 of 79 pages
<PAGE> 36
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
PRO FORMA INFORMATION
YEAR ENDED DECEMBER 31,
--------------------------------
1999 1998
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C>
REVENUES
Oil sales $ 702,477 487,218
Gas sales 806,337 802,785
Natural gas liquids sales 93,829 71,726
Other 87,453 306,103
-------------- --------------
Total revenues 1,690,096 1,667,832
-------------- --------------
COSTS AND EXPENSES
Lease operating expenses 409,555 444,617
Production taxes 53,506 44,548
Depreciation, depletion and amortization of property
and equipment 665,865 723,908
Amortization of goodwill 46,321 52,637
General and administrative expenses 147,028 177,678
Expenses related to prior mergers 16,800 13,149
Interest expense 158,813 175,082
Deferred effect of changes in foreign currency exchange rate on
subsidiary's long-term debt (13,154) 16,104
Distributions on preferred securities of subsidiary trust 6,884 9,717
Reduction of carrying value of oil and gas properties 476,100 422,500
-------------- --------------
Total costs and expenses 1,967,718 2,079,940
-------------- --------------
Earnings (loss) before income tax expense and extraordinary item (277,622) (412,108)
INCOME TAX EXPENSE (BENEFIT)
Current 23,261 (1,076)
Deferred (93,173) (109,222)
-------------- --------------
Total income tax expense (benefit) (69,912) (110,298)
-------------- --------------
Earnings (loss) before extraordinary item (207,710) (301,810)
Preferred stock dividends 9,736 5,625
-------------- --------------
Earnings (loss) before extraordinary item applicable to
common stockholders $ (217,446) (307,435)
============== ==============
Earnings (loss) before extraordinary item per average common
share outstanding - basic and diluted $ (1.81) (2.61)
============== ==============
Weighted average common shares outstanding - basic 119,988 117,703
============== ==============
</TABLE>
Northstar Combination
On June 29, 1998, Devon and Northstar Energy Corporation ("Northstar")
announced they had entered into a definitive combination agreement subject to
shareholder approval and certain other conditions. The combination of the two
companies (the "Northstar combination") was closed on December 10, 1998. At that
date, Northstar became a wholly-owned subsidiary of Devon. Pursuant to the
Northstar combination, Northstar's common shareholders received approximately
16.1 million exchangeable shares (the "Exchangeable Shares") based on an
exchange ratio of 0.235 Exchangeable Shares for each Northstar common share
outstanding. The Exchangeable Shares were issued by Northstar, but are
exchangeable at any time into Devon's common shares on a one-for-one basis.
Prior to such exchange, the Exchangeable Shares have rights identical to those
of Devon's common shares, including dividend, voting and liquidation rights.
Between December 10, 1998 and December 31, 1999, approximately 11.4 million of
the originally issued 16.1 million Exchangeable Shares had been exchanged for
shares of Devon common stock.
The Northstar combination was accounted for under the
pooling-of-interests method of accounting for business combinations. All
operational and financial information contained herein includes the combined
amounts for Devon and Northstar for all periods presented.
During the fourth quarter of 1998, Devon recorded a pre-tax charge of
$13.1 million ($9.7 million after tax) for direct costs related to the Northstar
combination.
Page 36 of 79 pages
<PAGE> 37
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Morrison Transaction
In March 1997, Northstar acquired all the outstanding common shares of
Morrison Petroleums Ltd. ("Morrison"), an independent oil and gas producer also
located in Alberta, Canada. Northstar acquired the Morrison common shares by
issuing common shares of Northstar (the "Morrison Transaction"). The Northstar
common shares received by the Morrison shareholders represented approximately
53% of the combined company's outstanding shares. Therefore, this transaction
was accounted for as a reverse acquisition under U.S. generally accepted
accounting principles. Accordingly, Northstar's results through March 31, 1997,
which are combined with Devon's results in the accompanying consolidated
financial statements, represent the historical results of Morrison, the
"accounting acquirer." Because Northstar was the "legal acquirer," the financial
results and other information for periods through March 31, 1997, are referred
to as "Northstar's" results and information, even though they represent the
historical results of Morrison. For periods subsequent to March 31, 1997,
Northstar's results that are combined with Devon's results represent the
historical results of Morrison, combined with Northstar's results after valuing
Northstar's March 31, 1997, assets and liabilities at fair value, rather than
historical book value.
The estimated proved reserves added in the Morrison Transaction were
18.3 million barrels of oil, 213.5 billion cubic feet of natural gas and 2.9
million barrels of natural gas liquids. Also added in the Morrison Transaction
were approximately 563,000 net acres of undeveloped leasehold. (The quantities
of proved reserves stated in this paragraph are unaudited.)
After giving effect to the Northstar combination exchange ratio of
0.235, approximately 9.8 million Exchangeable Shares are deemed to have been
issued in the Morrison Transaction with a total value of approximately $441.6
million. Also, approximately $111.3 million of liabilities were assumed and
$128.5 million of additional deferred tax liabilities were recorded due to the
tax-free nature of the Morrison Transaction to the Morrison shareholders.
Excluding the $128.5 million of additional deferred tax liabilities, the total
purchase price was allocated $435.2 million to proved oil and gas reserves,
$37.3 million to undeveloped leasehold and $80.4 million to other assets
acquired. Including the $128.5 million of deferred tax liabilities, the
allocation was $527.9 million to proved oil and gas reserves, $43.5 million to
undeveloped leasehold and $110.0 million to other assets.
Spin-off of Monterey Resources, Inc.
Santa Fe Snyder formed Monterey Resources, Inc. ("Monterey") in 1996 to
assume the operations of its Western Division which conducted its oil and gas
operations in the State of California. In November 1996, Monterey sold 9.3
million shares of its common stock (17.2%) in an initial public offering. On
July 25, 1997, Santa Fe Snyder distributed pro rata to its common shareholders
all of the shares of Monterey's common stock that it owned (82.8% of the
outstanding Monterey common stock) by means of a tax-free distribution.
Monterey agreed to indemnify Santa Fe Synder if at any time during the
one-year period subsequent to consummation of the spin-off (or if certain tax
legislation is enacted and is applicable, such longer period as is required for
the spin-off to be tax free to Santa Fe Snyder) Monterey takes certain actions,
the effects of which result in the spin-off being taxable to Santa Fe Synder.
Santa Fe Snyder does not believe that any such actions occurred during the
one-year period that would have had such effect on the spin-off.
Pursuant to the terms of the spin-off, Monterey agreed to indemnify and
hold harmless Santa Fe Synder from and against any costs incurred in the future
relating to environmental liabilities of the Western Division assets (other than
those retained by Santa Fe Synder), and any costs or liabilities that may arise
in the future that are attributable to laws, rules or regulations in respect to
any property or interest therein located in California and formerly owned or
operated by Santa Fe Snyder's Western Division or its predecessors.
Page 37 of 79 pages
<PAGE> 38
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
3. SAN JUAN BASIN TRANSACTION
At the beginning of 1995, Devon entered into a transaction (the "San
Juan Basin Transaction") involving a volumetric production payment and
repurchase option. The San Juan Basin Transaction allowed Devon to monetize tax
credits earned from certain of its coal seam gas production in the San Juan
Basin. During 1999, 1998 and 1997, the San Juan Basin Transaction added
approximately $7.6 million, $8.4 million and $8.5 million, respectively, to
Devon's gas revenues.
Under the terms of the San Juan Basin Transaction, Devon had a
repurchase option which it could exercise at anytime. Devon exercised the
repurchase option effective September 30, 2000. Devon recorded a portion of the
quarterly cash payments received pursuant to the San Juan Basin Transaction as a
repurchase liability based upon the estimated eventual repurchase price. Devon
also received cash payments in exchange for agreeing not to exercise its
repurchase option for specific periods of time prior to 2000. These payments
were also been added to the repurchase liability. As a result, in addition to
the cash flow recorded as revenues described in the previous paragraph, Devon
also received $16.6 million, $6.8 million and $6.2 million in 1999, 1998 and
1997, respectively, which were added to the repurchase liability. At December
31, 1999, the repurchase liability totaled $37.6 million. This amount is
included in other long-term liabilities in Devon's consolidated balance sheet.
The actual repurchase price as of September 30, 2000, was approximately $36.3
million.
4. SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments for interest in 1999, 1998 and 1997 were approximately
$115.6 million, $45.6 million and $28.2 million, respectively. Cash payments for
federal, state and foreign income taxes in 1999, 1998 and 1997 were
approximately $15.8 million, $19.4 million and $44.7 million, respectively.
The 1999 PennzEnergy merger and Snyder merger and the 1997 Morrison
Transaction involved non-cash consideration as presented below:
<TABLE>
<CAPTION>
1999 1997
------------ ------------
(IN THOUSANDS)
<S> <C> <C>
Value of common stock issued $ 1,130,269 441,590
Value of preferred stock issued 150,000 --
Employee stock options assumed 18,295 --
Liabilities assumed 2,259,174 111,345
Deferred tax liability created 474,306 128,497
------------ ------------
Fair value of assets acquired with
non-cash consideration $ 4,032,044 681,432
============ ============
</TABLE>
During the fourth quarter of 1999, substantially all of the 6.5% Trust
Convertible Preferred Securities were converted to Devon common stock (see Note
9).
The spin-off of Monterey in 1997 (see Note 2) involved non-cash
reductions in Devon's 1997 balance sheet. The reductions totaled $610.8 million
of assets, $404.3 million of liabilities, $31.1 million of minority interest and
$175.4 million of stockholders' equity.
Page 38 of 79 pages
<PAGE> 39
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
5. ACCOUNTS RECEIVABLE
The components of accounts receivable included the following:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1999 1998
------------- -------------
(IN THOUSANDS)
<S> <C> <C>
Oil, gas and natural gas liquids
revenue accruals $ 218,462 74,660
Joint interest billings 66,658 33,136
Other 34,585 31,262
------------- -------------
319,705 139,058
Allowance for doubtful accounts (3,700) (2,000)
------------- -------------
Net accounts receivable $ 316,005 137,058
============= =============
</TABLE>
6. PROPERTY AND EQUIPMENT
Property and equipment included the following:
<TABLE>
<CAPTION>
DECEMBER 31,
1999 1998
------------- -------------
(IN THOUSANDS)
<S> <C> <C>
Oil and gas properties:
Subject to amortization $ 8,125,886 4,584,676
Not subject to amortization:
Acquired in 1999 134,966 --
Acquired in 1998 56,922 65,702
Acquired in 1997 51,677 70,261
Acquired prior to 1997 57,620 77,614
Accumulated depreciation, depletion
and amortization (4,129,824) (3,204,775)
------------- -------------
Net oil and gas properties 4,297,247 1,593,478
------------- -------------
Other property and equipment 164,939 55,958
Accumulated depreciation and amortization (38,766) (25,908)
------------- -------------
Net other property and equipment 126,173 30,050
------------- -------------
Property and equipment, net of
accumulated depreciation,
depletion and amortization $ 4,423,420 1,623,528
============= =============
</TABLE>
Depreciation, depletion and amortization of property and equipment
consisted of the following components:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
1999 1998 1997
------------- ------------- -------------
(IN THOUSANDS)
<S> <C> <C> <C>
Depreciation, depletion and amortization
of oil and gas properties $ 390,117 230,419 276,977
Depreciation and amortization of other
property and equipment 13,660 12,564 8,166
Amortization of other assets 2,598 161 565
------------- ------------- -------------
Total expense $ 406,375 243,144 285,708
============= ============= =============
</TABLE>
Page 39 of 79 pages
<PAGE> 40
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
7. LONG-TERM DEBT AND RELATED EXPENSES
A summary of Devon's long-term debt is as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------------
1999
------------------------------
PRO FORMA(A) ACTUAL 1998
------------- ------------- -------------
(IN THOUSANDS)
<S> <C> <C> <C>
Borrowings under credit facilities with banks $ 745,141 645,141 411,271
Debentures exchangeable into shares of Chevron
Corporation common stock:
4.90% due August 15, 2008 443,807 443,807 --
4.95% due August 15, 2008 316,506 316,506 --
Other debentures:
10.25% due November 1, 2005 250,000 250,000 --
10.125% due November 15, 2009 200,000 200,000 --
11.000% due May 15, 2004 -- -- 100,000
Premium (discount) on debentures 37,467 37,467 (400)
Senior notes:
8.05% due June 15, 2004 125,000 125,000 --
6.76% due July 19, 2005 -- 75,000 75,000
8.75% due June 15, 2007 175,000 175,000 --
6.79% due March 2, 2009 -- 150,000 150,000
Discount on notes (1,400) (1,400) --
------------- ------------- -------------
2,291,521 2,416,521 735,871
Less amount classified as current -- -- --
------------- ------------- -------------
Long-term debt $ 2,291,521 2,416,521 735,871
============= ============= =============
</TABLE>
Maturities of long-term debt as of December 31, 1999, excluding the
$36.1 million of premiums net of discounts, are as follows (in thousands):
<TABLE>
<CAPTION>
PRO FORMA(a) ACTUAL
----------- ----------
<S> <C> <C>
2000 $ -- --
2001 9,467 20,717
2002 84,467 20,717
2003 9,467 20,717
2004 615,267 676,517
2005 and thereafter 1,536,786 1,641,786
---------- ----------
Total $2,255,454 2,380,454
========== ==========
</TABLE>
(A) A discussion of pro forma debt outstanding is included later in
this note.
Credit Facilities With Banks
Prior to the August 2000 merger, Devon and Santa Fe Snyder each had
their own unsecured credit facilities under which a combined total of $645.1
million was borrowed as of December 31, 1999. Devon's credit facilities prior to
the merger aggregated $750 million, with $475 million in a U.S. facility and
$275 million in a Canadian facility. These Devon credit facilities were entered
into in October 1999. Santa Fe Snyder's credit facilities prior to the merger
aggregated $600 million. The weighted average interest rates on the combined
debt outstanding under the credit facilities at the end of 1999 and 1998 were
6.85% and 6.28%, respectively. The agreements governing the separate credit
facilities contained certain covenants and restrictions. At December 31, 1999,
Devon and Santa Fe Snyder were in compliance with such covenants and
restrictions of their respective agreements.
Concurrent with the closing of the Santa Fe Snyder merger on August 29,
2000, Devon entered into new unsecured long-term credit facilities aggregating
$1 billion (the "Credit Facilities"). The Credit Facilities replaced the prior
separate facilities of Devon and Santa Fe Snyder. The Credit Facilities include
a U.S. facility of $725 million (the "U.S. Facility") and a Canadian facility of
$275 million (the "Canadian Facility").
Page 40 of 79 pages
<PAGE> 41
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
The $725 million U.S. Facility consists of a Tranche A facility of $200
million and a Tranche B facility of $525 million. The Tranche B facility can be
increased to as high as $625 million and reduced to as low as $425 million by
reallocating the amount available between the Tranche B facility and the
Canadian Facility. The Tranche A facility matures on October 15, 2004. Devon may
borrow funds under the Tranche B facility until August 28, 2001 (the "Tranche B
Revolving Period"). Devon may request that the Tranche B Revolving Period be
extended an additional 364 days by notifying the agent bank of such request
between 30 and 60 days prior to the end of the Tranche B Revolving Period. Debt
borrowed under the Tranche B facility matures two years and one day following
the end of the Tranche B Revolving Period.
Devon may borrow funds under the $275 million Canadian Facility until
August 28, 2001 (the "Canadian Facility Revolving Period"). As disclosed in the
prior paragraph, the Canadian Facility can be increased to as high as $375
million and reduced to as low as $175 million by reallocating the amount
available between the Tranche B facility and the Canadian Facility. Devon may
request that the Canadian Facility Revolving Period be extended an additional
364 days by notifying the agent bank of such request between 45 and 90 days
prior to the end of the Canadian Facility Revolving Period. Debt outstanding as
of the end of the Canadian Facility Revolving Period is payable in semi-annual
installments of 2.5% each for the following five years, with the final
installment due five years and one day following the end of the Canadian
Facility Revolving Period.
Amounts borrowed under the Credit Facilities bear interest at various
fixed rate options that Devon may elect for periods up to six months. Such rates
are generally less than the prime rate, and are tied to margins determined by
Devon's corporate credit ratings. Devon may also elect to borrow at the prime
rate. The Credit Facilities provide for an annual facility fee of $0.9 million
that is payable quarterly.
Exchangeable Debentures
The exchangeable debentures consist of $443.8 million of 4.90%
debentures and $316.5 million of 4.95% debentures. The exchangeable debentures
were issued on August 3, 1998, mature August 15, 2008, and are callable
beginning August 15, 2000. The exchangeable debentures are exchangeable at the
option of the holders at any time prior to maturity, unless previously redeemed,
for shares of Chevron Corporation common stock. In lieu of delivering Chevron
Corporation common stock, Devon may, at its option, pay to any holder an amount
of cash equal to the market value of the Chevron Corporation common stock to
satisfy the exchange request. However, at maturity, the holders will receive an
amount at least equal to the face value of the debt outstanding - either in cash
or in a combination of cash and Chevron Corporation common stock.
As of December 31, 1999, Devon beneficially owned approximately 7.1
million shares of Chevron Corporation common stock. These shares have been
deposited with an exchange agent for possible exchange for the exchangeable
debentures. Each $1,000 principal amount of the exchangeable debentures is
exchangeable into 9.3283 shares of Chevron Corporation common stock, an exchange
rate equivalent to $107 7/32 per share of Chevron stock.
The exchangeable debentures were assumed as part of the PennzEnergy
merger. The fair values of the exchangeable debentures were determined as of
August 17, 1999, based on market quotations. The fair value approximated the
face value of the exchangeable debentures. As a result, no premium or discount
was recorded on these exchangeable debentures.
Other Debentures
The 10.25% and 10.125% debentures were assumed as part of the
PennzEnergy merger. The fair values of the respective debentures were determined
using August 17, 1999, market interest rates. As a result, premiums were
recorded on these debentures which lowered their effective interest rates to
8.3% and 8.9% on the $250 million of 10.25% debentures and $200 million of
10.125% debentures, respectively. The premiums are being amortized using the
effective interest method.
Page 41 of 79 pages
<PAGE> 42
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Senior Notes
Northstar issued the 6.76% notes in a private placement in 1995. The
notes were unsecured and were payable in five annual installments of $15 million
each beginning in 2001. In mid-January 2000, Devon retired these notes. See the
"Pro Forma" section below.
Northstar issued the 6.79% notes in a private placement in 1998. The
notes were unsecured and were payable in three annual installments of $50
million each beginning in 2007. Proceeds from these notes were partially used to
retire $60 million of 7.03% notes. In mid-January 2000, Devon also retired the
6.79% notes issued in 1998. See the "Pro Forma" section below.
The agreements governing the two Northstar Senior Notes contained
certain covenants and restrictions specific to Northstar, including maintenance
of certain debt-to-capitalization and debt-to-EBITDA ratios and a minimum
tangible net worth as well as restrictions on additional borrowings. At December
31, 1999, Northstar was in compliance with such covenants and restrictions.
In connection with the Snyder merger, Devon assumed Snyder's $175
million of 8.75% notes due in 2007. The notes are redeemable by Devon on or
after June 15, 2002, initially at 104.375% of principal and at prices declining
to 100% of principal on or after June 15, 2005. The notes are general unsecured
obligations of Devon. In June 1999 Devon issued $125.0 million of 8.05% notes
due 2004. The notes were issued for 98.758% of face value and Devon received
total proceeds of $121.6 million after deducting related costs and expenses of
$1.9 million. The notes, which mature June 15, 2004, are redeemable, upon not
less than thirty nor more than sixty days notice, as a whole or in part, at the
option of Devon at a redemption price equal to the sum of (i) 100% of the
principal amount thereof, (ii) the applicable make-whole premium as determined
by an independent investment banker and (iii) accrued and unpaid interest. The
notes are general unsecured obligations of Devon. The indentures for these notes
include covenants that restrict the ability of Devon SFS Operating, Inc., a
wholly-owned subsidiary of Devon, to take certain actions, including the ability
to incur additional indebtedness and to pay dividends or repurchase capital
stock.
Convertible Debentures
In June 2000, Devon privately sold zero-coupon convertible senior debentures
("Convertible Debentures"). The Convertible Debentures were sold at a price of
$464.13 per debenture with a yield to maturity of 3.875% per annum. Each
debenture is convertible into 5.7593 shares of Devon common stock. Devon may
call the bonds at any time after five years, and a debenture holder has the
right to require Devon to repurchase the bonds after five, 10 and 15 years, at
the issue price plus accrued original issue discount and interest. Devon's
proceeds were approximately $346.1 million, net of debt issuance costs of
approximately $6.6 million. Devon used the proceeds from the sale of these
Convertible Debentures to pay down other domestic long-term debt.
Pro Forma
In January 2000, Devon used excess cash of $75 million, together with
borrowings of $150 million under its previous credit facilities, to retire the
$225 million of Senior Notes outstanding as of December 31, 1999. Also in
January 2000, Devon used an additional $50 million of excess cash to pay down
borrowings under its previous credit facilities. The result of these early 2000
transactions left $745.1 million outstanding under the previous credit
facilities.
Page 42 of 79 pages
<PAGE> 43
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Interest Expense
Following are the components of interest expense for the years 1999,
1998 and 1997:
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Interest based on debt outstanding $ 108,064 43,114 36,945
Amortization of premium on (1,328) -- --
debentures
Facility and agency fees 1,930 932 998
Amortization of capitalized loan 1,583 556 918
costs
Penalty on early retirement of debt -- -- 3,323
Hedging gains -- (188) (410)
Other (636) (882) (286)
--------- --------- ---------
Total interest expense $ 109,613 43,532 41,488
========= ========= =========
</TABLE>
Deferred Effect of Changes in Foreign Currency Exchange Rate on Long-term Debt
The fixed-rate Senior Notes referred to in the first table of this note
were payable by Northstar. However, the notes were denominated in U.S. dollars.
Changes in the exchange rate between the U.S. dollar and the Canadian dollar
from the dates the notes were issued to the dates of repayment increased or
decreased the expected amount of Canadian dollars eventually required to repay
the notes. Such changes in the Canadian dollar equivalent of the debt were
required to be included in determining net earnings for the period in which the
exchange rate changed. The rate of conversion of Canadian dollars to U.S.
dollars increased in 1999 and declined in 1998 and 1997. Therefore, $13.2
million of reduced expense was recorded in 1999, and $16.1 million and $5.9
million of increased expenses were recorded in 1998 and 1997, respectively.
8. INCOME TAXES
At December 31, 1999, Devon had the following carryforwards available
to reduce future income taxes:
<TABLE>
<CAPTION>
YEARS OF CARRYFORWARD
TYPES OF CARRYFORWARD EXPIRATION AMOUNTS
-------------- --------------
(IN THOUSANDS)
<S> <C> <C>
Net operating loss - U.S. federal 2000 - 2019 $ 547,762
Net operating loss - various states 2000 - 2013 $ 157,801
Net operating loss - Canada 2000 - 2005 $ 85,254
Minimum tax credits Indefinite $ 88,447
</TABLE>
All of the carryforward amounts shown above have been utilized for
financial purposes to reduce deferred taxes.
Page 43 of 79 pages
<PAGE> 44
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
The earnings (loss) before income taxes and the components of income
tax expense (benefit) for the years 1999, 1998 and 1997 were as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
1999 1998 1997
------------ ------------ ------------
(IN THOUSANDS)
Earnings (loss) before income taxes:
<S> <C> <C> <C>
U.S $ (313,101) (274,150) 238,465
Canada 57,402 19,958 (580,498)
Other 56,321 (107,800) 1,800
------------ ------------ ------------
Total $ (199,378) (361,992) (340,233)
============ ============ ============
Current income tax expense (benefit):
U.S. federal 12,544 (6,399) 20,959
Various states 2,804 (1,189) 3,921
Canada 2,908 1,975 5,677
Other 4,800 1,900 5,200
------------ ------------ ------------
Total current tax expense 23,056 (3,713) 35,757
------------ ------------ ------------
Deferred income tax expense (benefit):
U.S. federal (119,286) (88,824) 60,225
Various states (495) (4,836) 2,278
Canada 26,654 11,166 (219,302)
Other 20,637 (39,900) (5,700)
------------ ------------ ------------
Total deferred tax expense (benefit) (72,490) (122,394) (162,499)
------------ ------------ ------------
Total income tax expense (benefit) $ (49,434) (126,107) (126,742)
============ ============ ============
</TABLE>
Total income tax expense differed from the amounts computed by applying
the U.S. federal income tax rate to earnings (loss) before income taxes as a
result of the following:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1999 1998 1997
----- ----- -----
<S> <C> <C> <C>
U.S. statutory tax (benefit) rate (35)% (35)% (35)%
Non-deductible expenses 3 3 --
Nonconventional fuel source credit (3) (1) --
State income taxes 1 (1) 1
Taxation on foreign operations 7 2 (3)
Other 2 (3) --
----- ----- -----
Effective income tax (benefit)rate (25)% (35)% (37)%
===== ===== =====
</TABLE>
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax assets and liabilities at December 31, 1999 and
1998 are presented below:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1999 1998
--------- ---------
(IN THOUSANDS)
Deferred tax assets:
<S> <C> <C>
Net operating loss carryforwards $ 207,322 48,418
Minimum tax credit carryforwards 88,447 16,900
Production payments 21,527 19,105
Long-term debt 17,583 --
Other 50,618 20,388
--------- ---------
Total gross deferred tax assets 385,497 104,811
Less valuation allowance 100 100
--------- ---------
Net deferred tax assets 385,397 104,711
--------- ---------
Deferred tax liabilities:
Property and equipment, principally
due to differences in depreciation,
and the expensing of intangible
drilling costs for tax purposes (500,156) (49,256)
Chevron Corporation common stock (172,631) --
Other (31,789) (469)
--------- ---------
Total deferred tax liabilities (704,576) (49,725)
--------- ---------
Net deferred tax asset (liability) $(319,179) 54,986
========= =========
</TABLE>
As shown in the above schedule, Devon has recognized $385.4 million of
net deferred tax assets as of December 31, 1999. Such amount consists primarily
of $295.8 million of various carryforwards available to offset future income
taxes. The
Page 44 of 79 pages
<PAGE> 45
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
carryforwards include federal net operating loss carryforwards, the majority of
which do not begin to expire until 2008, state net operating loss carryforwards
which expire primarily between 2000 and 2013, Canadian carryforwards which
expire primarily between 2000 and 2005, and minimum tax credit carryforwards
which have no expiration. The tax benefits of carryforwards are recorded as an
asset to the extent that management assesses the utilization of such
carryforwards to be "more likely than not." When the future utilization of some
portion of the carryforwards is determined not to be "more likely than not," a
valuation allowance is provided to reduce the recorded tax benefits from such
assets.
Devon expects the tax benefits from the net operating loss
carryforwards to be utilized between 2000 and 2006. Such expectation is based
upon current estimates of taxable income during this period, considering
limitations on the annual utilization of these benefits as set forth by federal
tax regulations. Significant changes in such estimates caused by variables such
as future oil and gas prices or capital expenditures could alter the timing of
the eventual utilization of such carryforwards. There can be no assurance that
Devon will generate any specific level of continuing taxable earnings. However,
management believes that Devon's future taxable income will more likely than not
be sufficient to utilize substantially all its tax carryforwards prior to their
expiration. A $0.1 million valuation allowance has been recorded at December 31,
1999, related to depletion carryforwards acquired in a 1994 merger.
The $21.5 million of deferred tax assets related to production payments
is offset by a portion of the deferred tax liability related to the excess
financial basis of property and equipment. The income tax accounting for the San
Juan Basin Transaction described in Note 3 differs from the financial accounting
treatment. For income tax purposes, a gain from the conveyance of the properties
was realized, and the present value of the production payments to be received
was recorded as a note receivable. For presentation purposes, the $21.5 million
represents the tax effect of the difference in accounting for the production
payment, less the effect of the taxable gain from the transaction which is being
deferred and recognized on the installment basis for income tax purposes.
9. TRUST CONVERTIBLE PREFERRED SECURITIES
On July 10, 1996, Devon, through its affiliate Devon Financing Trust,
completed the issuance of $149.5 million of 6.5% trust convertible preferred
securities (the "TCP Securities"). Devon Financing Trust issued 2,990,000 shares
of the TCP Securities at $50 per share with a maturity date of June 15, 2026.
Each TCP Security was convertible at the holder's option into 1.6393 shares of
Devon common stock, which equates to a conversion price of $30.50 per share of
Devon common stock.
Devon Financing Trust invested the $149.5 million of proceeds in 6.5%
convertible junior subordinated debentures issued by Devon (the "Convertible
Debentures"). In turn, Devon used the net proceeds from the issuance of the
Convertible Debentures to retire debt outstanding under its credit lines.
On October 27, 1999, Devon issued notice to the holders of the TCP
Securities that it was exercising its right to redeem such securities on
November 30, 1999. Substantially all of the holders of the TCP Securities
elected to exercise their conversion rights instead of receiving the redemption
cash value. As a result, all but 950 shares of the TCP Securities were converted
into approximately 4.9 million shares of Devon common stock. The redemption
price for the 950 shares not converted was $52.275 per share, or $50,000 total,
which included a 4.55% premium as required under the terms of the TCP
Securities.
Devon owned all the common securities of Devon Financing Trust. As
such, the accounts of Devon Financing Trust were included in Devon's
consolidated financial statements after appropriate eliminations of intercompany
balances and transactions. The distributions on the TCP Securities were recorded
as a charge to pre-tax earnings on Devon's consolidated statements of
operations, and such distributions were deductible by Devon for income tax
purposes.
Page 45 of 69 pages
<PAGE> 46
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
10. STOCKHOLDERS' EQUITY
The authorized capital stock of Devon consists of 400 million shares of
common stock, par value $.10 per share (the "Common Stock"), and 4.5 million
shares of preferred stock, par value $1.00 per share. The preferred stock may be
issued in one or more series, and the terms and rights of such stock will be
determined by the Board of Directors.
Effective August 17, 1999, Devon issued 1.5 million shares of 6.49%
cumulative preferred stock, Series A, to holders of PennzEnergy 6.49% cumulative
preferred stock, Series A. Dividends on the preferred stock are cumulative from
the date of original issue and are payable quarterly, in cash, when declared by
the Board of Directors. The preferred stock is redeemable at the option of Devon
at any time on or after June 2, 2008, in whole or in part, at a redemption price
of $100 per share, plus accrued and unpaid dividends to the redemption date.
In late September and early October 1999, Devon received $402.7 million
from the sale of approximately 10.3 million shares of its common stock in a
public offering. The price to the public for these shares was $40.50 per share.
Net of underwriters' discount and commissions, Devon received $38.98 per share.
Devon paid approximately $0.8 million of expenses related to the equity
offering, and these costs were recorded as reductions of additional paid-in
capital.
As discussed in Note 2, there were approximately 21.5 million shares of
Devon common stock issued on August 17, 1999, in connection with the PennzEnergy
merger. Also, as discussed in Note 2, there were 16.1 million Exchangeable
Shares issued on December 10, 1998, in connection with the Northstar
Combination. As of year-end 1999, 11.4 million of the Exchangeable Shares had
been exchanged for shares of Devon's common stock. The Exchangeable Shares have
rights identical to those of Devon's common stock and are exchangeable at any
time into Devon's common stock on a one-for-one basis.
Devon's Board of Directors has designated 1.0 million shares of the
preferred stock as Series A Junior Participating Preferred Stock (the "Series A
Junior Preferred Stock") in connection with the adoption of the share rights
plan described later in this note. At December 31, 1999, there were no shares of
Series A Junior Preferred Stock issued or outstanding. The Series A Junior
Preferred Stock is entitled to receive cumulative quarterly dividends per share
equal to the greater of $10 or 100 times the aggregate per share amount of all
dividends (other than stock dividends) declared on Common Stock since the
immediately preceding quarterly dividend payment date or, with respect to the
first payment date, since the first issuance of Series A Junior Preferred Stock.
Holders of the Series A Junior Preferred Stock are entitled to 100 votes per
share (subject to adjustment to prevent dilution) on all matters submitted to a
vote of the stockholders. The Series A Junior Preferred Stock is neither
redeemable nor convertible. The Series A Junior Preferred Stock ranks prior to
the Common Stock but junior to all other classes of Preferred Stock.
Stock Option Plans
Devon has outstanding stock options issued to key management and
professional employees under three stock option plans adopted in 1988, 1993 and
1997 (the "1988 Plan," the "1993 Plan" and the "1997 Plan"). Options granted
under the 1988 Plan and 1993 Plan remain exercisable by the employees owning
such options, but no new options will be granted under these plans. At December
31, 1999, there were 189,000 and 740,500 options outstanding under the 1988 Plan
and the 1993 Plan, respectively.
On May 21, 1997, Devon's stockholders adopted the 1997 Plan and
reserved two million shares of Common Stock for issuance thereunder. On December
9, 1998, Devon's stockholders voted to increase the reserved number of shares to
three million. On August 17, 1999, Devon's stockholders voted to increase the
reserved number of shares to six million. On August 29, 2000, Devon's
stockholders voted to increase the reserved number of shares to ten million.
Page 46 of 79 pages
<PAGE> 47
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
The exercise price of stock options granted under the 1997 Plan may not
be less than the estimated fair market value of the stock at the date of grant,
plus 10% if the grantee owns or controls more than 10% of the total voting stock
of Devon prior to the grant. Options granted are exercisable during a period
established for each grant, which period may not exceed 10 years from the date
of grant. Under the 1997 Plan, the grantee must pay the exercise price in cash
or in Common Stock, or a combination thereof, at the time that the option is
exercised. The 1997 Plan is administered by a committee comprised of
non-management members of the Board of Directors. The 1997 Plan expires on April
25, 2007. As of December 31, 1999, there were 2,142,150 options outstanding
under the 1997 Plan. There were 3,725,550 options available for future grants as
of December 31, 1999.
In addition to the stock options outstanding under the 1988 Plan, 1993
Plan and 1997 Plan, there were approximately 3,174,600, 2,081,100 and 226,600
stock options outstanding at the end of 1999 that were assumed as part of the
Santa Fe Snyder merger, the PennzEnergy merger and the Northstar Combination,
respectively. Santa Fe Snyder, PennzEnergy and Northstar had granted these
options prior to the Santa Fe Snyder merger, the PennzEnergy merger and the
Northstar Combination. As part of the Santa Fe Snyder merger, the PennzEnergy
merger and the Northstar Combination, the options were assumed by Devon and
converted to Devon options at the exchange rate of 0.22, 0.4475 and 0.235 Devon
options for each Santa Fe Snyder, PennzEnergy and Northstar option,
respectively.
A summary of the status of Devon's stock option plans as of December
31, 1997, 1998 and 1999, and changes during each of the years then ended, is
presented below.
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
---------------------------- ---------------------------
WEIGHTED
AVERAGE
NUMBER EXERCISE NUMBER EXERCISE
OUTSTANDING PRICE EXERCISABLE PRICE
----------- ---------- ----------- ----------
<S> <C> <C> <C> <C>
Balance at December 31, 1996 3,212,023 $ 37.483 2,050,483 $ 38.337
========== ==========
Options assumed in the
Morrison Transaction 732,041 $ 36.260
Options granted 883,849 $ 35.060
Options exercised (574,016) $ 27.418
Options forfeited (534,517) $ 42.790
Revaluation due to Monterey Spinoff 686,180 $ 33.045
----------
Balance at December 31, 1997 4,405,560 $ 31.564 2,744,115 $ 29.717
========== ==========
Options granted 1,652,789 $ 34.262
Options exercised (187,953) $ 23.943
Options forfeited (349,740) $ 35.326
----------
Balance at December 31, 1998 5,520,656 $ 31.768 4,079,125 $ 30.479
========== ==========
Options granted 1,564,108 $ 31.736
Options assumed in the
PennzEnergy merger 2,081,894 $ 55.643
Options assumed in the Snyder merger 979,220 $ 35.182
Options exercised (1,139,231) $ 28.509
Options forfeited (452,746) $ 36.369
----------
Balance at December 31, 1999 8,553,901 $ 38.202 7,063,983 $ 39.547
========== ========== ==========
</TABLE>
The weighted average fair values of options granted during 1999, 1998
and 1997 were $12.80, $13.44 and $14.36, respectively. The fair value of each
option grant was estimated for disclosure purposes on the date of grant using
the Black-Scholes Option Pricing Model with the following assumptions for 1999,
1998 and 1997, respectively: risk-free interest rates of 6.0%, 5.0% and 6.1%;
dividend yields of 0.5%, 0.4% and 0.1%; expected lives of 5, 5 and 6 years; and
volatility of the price of the underlying common stock of 35.2%, 31.7% and
29.7%.
Page 47 of 79 pages
<PAGE> 48
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
The following table summarizes information about Devon's stock options
which were outstanding, and those which were exercisable, as of December 31,
1999:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------- --------------------------
WEIGHTED WEIGHTED WEIGHTED
RANGE OF AVERAGE AVERAGE AVERAGE
EXERCISE NUMBER REMAINING EXERCISE NUMBER EXERCISE
PRICES OUTSTANDING LIFE PRICE EXERCISABLE PRICE
--------------- ---------------- --------------- --------------- --------------- -----------
<S> <C> <C> <C> <C> <C>
$ 8.375-$25.667 1,482,708 4.0 years $ 22.897 1,467,842 $ 22.879
$26.291-$30.667 808,153 5.5 years $ 29.065 689,595 $ 29.055
$30.938-$34.375 1,860,742 8.1 years $ 31.412 796,201 $ 31.922
$35.582-$39.773 2,227,029 6.6 years $ 37.017 1,948,056 $ 37.169
$40.125-$61.405 1,433,272 5.4 years $ 51.397 1,420,282 $ 51.471
$63.433-$92.781 741,997 5.2 years $ 73.872 741,997 $ 73.872
--------- ---------
8,553,901 6.1 years $ 38.205 7,063,973 $ 39.547
========= =========
</TABLE>
Had Devon elected the fair value provisions of SFAS No. 123 and
recognized compensation expense over the vesting period based on the fair value
of the stock options granted as of their grant date, Devon's 1999, 1998 and 1997
pro forma net earnings (loss) and pro forma net earnings (loss) per share would
have differed from the amounts actually reported as shown in the following
table. The pro forma amounts shown below do not include the effects of stock
options granted prior to January 1, 1995.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------
1999 1998 1997
--------------- --------------- ------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
Net earnings (loss) available to common shareholders:
As reported $ (157,795) (235,885) (230,191)
Pro forma $ (173,005) (252,070) (238,492)
Net earnings (loss) per share available to common shareholders:
As reported:
Basic and diluted $ (1.68) (3.32) (3.35)
Pro forma:
Basic and diluted $ (1.85) (3.55) (3.46)
</TABLE>
Share Rights Plan
Under Devon's share rights plan, stockholders have one right for each
share of Common Stock held. The rights become exercisable and separately
transferable ten business days after a) an announcement that a person has
acquired, or obtained the right to acquire, 15% or more of the voting shares
outstanding, or b) commencement of a tender or exchange offer that could result
in a person owning 15% or more of the voting shares outstanding.
Each right entitles its holder (except a holder who is the acquiring
person) to purchase either a) 1/100 of a share of Series A Preferred Stock for
$75.00, subject to adjustment or b) Devon Common Stock with a value equal to
twice the exercise price of the right, subject to adjustment to prevent
dilution. In the event of certain merger or asset sale transactions with another
party or transactions which would increase the equity ownership of a shareholder
who then owned 15% or more of Devon, each Devon right will entitle its holder to
purchase securities of the merging or acquiring party with a value equal to
twice the exercise price of the right.
The rights, which have no voting power, expire on April 16, 2005. The
rights may be redeemed by Devon for $.01 per right until the rights become
exercisable.
Page 48 of 79 pages
<PAGE> 49
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
11. FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair
values of Devon's financial instruments at December 31, 1999 and 1998.
<TABLE>
<CAPTION>
1999 1998
------------------------------ ---------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
----------- ---------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Investments $ 634,281 634,281 1,930 1,930
Oil and gas price hedge agreements $ -- (9,540) -- 1,988
Foreign exchange hedge agreements $ -- (2,535) -- (9,310)
Long-term debt (including current $(2,416,521) (2,400,334) (735,871) (758,075)
portion)
TCP Securities $ -- -- (149,500) (171,400)
</TABLE>
The following methods and assumptions were used to estimate the fair
values of the financial instruments in the above table. None of Devon's
financial instruments are held for trading purposes. The carrying values of cash
and cash equivalents, accounts receivable and accounts payable (including income
taxes payable and accrued expenses) included in the accompanying consolidated
balance sheets approximated fair value at December 31, 1999 and 1998.
Investments - The fair values of investments are primarily based on
quoted market prices.
Oil and Gas Price Hedge Agreements - The fair values of the oil and gas
price hedges are based on either (a) quotes obtained from the counterparty to
the hedge agreement or (b) quotes provided by brokers.
Foreign Exchange Hedge Agreements - The fair values of the foreign
exchange agreements are based on quotes obtained from brokers.
Long-term Debt - The fair values of the fixed-rate long-term debt have
been estimated based on quotes obtained from brokers or by discounting the
principal and interest payments at rates available for debt of similar terms and
maturity. The fair values of the floating-rate long-term debt are estimated to
approximate the carrying amounts due to the fact that the interest rates paid on
such debt are generally set for periods of three months or less.
TCP Securities - The fair values of the TCP Securities are based on
quoted market prices provided by brokers.
The following table covers Devon's notional volumes and pricing on open
natural gas hedging instruments as of December 31, 1999:
<TABLE>
<CAPTION>
YEAR OF PRODUCTION
--------------------------------------------
2000 2001 2002
---------- ------ -----
<S> <C> <C> <C>
Volumes (billion British thermal units) 18,215 12,661 2,656
Average price to be received $ 1.82 1.87 1.83
</TABLE>
The floating reference prices which Devon will pay the counterparties
to the above gas price hedging instruments include several index prices based
upon the area of the gas production that is hedged. For the hedged Canadian gas
production, these reference prices are primarily based on index prices published
by the Alberta Energy Company ("AECO"). For the hedged U.S. production, the
reference prices are primarily based on index prices published by "Inside FERC"
for the Rocky Mountains and San Juan Basin.
In addition to the above gas hedging instruments, Devon also had a
natural gas basis swap in effect as of December 31, 1999. In this basis swap,
which covers 20,000 MMBtus per day, Devon owes the counterparty the applicable
monthly Colorado Interstate Gas index price as published by Inside FERC, while
the counterparty owes Devon the average NYMEX
Page 49 of 79 pages
<PAGE> 50
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
price for the last three settlement days of the month less $0.30 per MMBtu. The
net difference is settled by the parties each month. This basis swap continues
through August 31, 2004.
At December 31, 1999, Devon also had various "price collars" in effect
for a portion of its oil production in the year 2000. These collars had an
average floor price of $20.20 per barrel and an average ceiling price of $25.06
per barrel. These collars were in place for an average daily production of
11,000 barrels per day during 2000.
Devon has certain foreign currency hedging instruments that offset a
portion of the exposure to currency fluctuations on Canadian oil sales that are
based on U.S. dollar prices. Gains and losses recognized on these foreign
currency hedging instruments are included as increases or decreases to realized
oil sales. As of December 31, 1999, Devon had open foreign currency hedging
instruments in which it will sell $30 million in 2000 at average
Canadian-to-U.S. dollar exchange rates of $0.7265. A portion of these hedging
instruments can be extended an additional year at the option of the
counterparty. If such options are exercised, Devon will sell an additional $10
million in 2001 at average Canadian-to-U.S. dollar exchange rates of $0.7102.
Under these agreements, Devon will buy the same amount of dollars in each year
at the floating exchange rate.
Devon's 1999, 1998 and 1997 consolidated balance sheets include
deferred revenues of $0.4 million, $1.0 million and $3.8 million, respectively,
for gains realized on the early termination of commodity and foreign currency
hedging instruments in prior years. These deferred gains as of the end of 1999
will be recognized as oil and gas sales over periods ranging from ten months to
one year as the hedged oil and gas production occurs.
12. RETIREMENT PLANS
Devon has non-contributory defined benefit retirement plans (the "Basic
Plans") which include U.S. employees meeting certain age and service
requirements. The benefits are based on the employee's years of service and
compensation. Devon's funding policy is to contribute annually the maximum
amount that can be deducted for federal income tax purposes. Rights to amend or
terminate the Basic Plans are retained by Devon.
Devon also has separate defined benefit retirement plans (the
"Supplementary Plans") which are non-contributory and include only certain
employees whose benefits under the Basic Plans are limited by income tax
regulations. The Supplementary Plans' benefits are based on the employee's years
of service and compensation. Devon's funding policy for the Supplementary Plans
is to fund the benefits as they become payable. Rights to amend or terminate the
Supplementary Plans are retained by Devon.
Additionally, Devon assumed responsibility for the PennzEnergy
sponsored defined benefit postretirement plans, which are unfunded, and cover
substantially all of the former PennzEnergy employees who remained with Devon.
Devon did not extend these benefits to other employees. The plans provide
medical and life insurance benefits and are, depending on the type of plan,
either contributory or non-contributory. The accounting for the health care plan
anticipates future cost-sharing changes that are consistent with Devon's
expressed intent to increase, where possible, contributions for future retirees.
Furthermore, future contributions for both current and future salaried retirees
have been limited to 200% of the 1992 retiree premium rates. Retirees will be
required to absorb all future cost increases over that limit.
Page 50 79 pages
<PAGE> 51
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
The following table sets forth the plans' benefit obligations, plan
assets, reconciliation of funded status, amounts recognized in the consolidated
balance sheets and the actuarial assumptions used as of December 31, 1999 and
1998.
<TABLE>
<CAPTION>
OTHER POSTRETIREMENT
PENSION BENEFITS BENEFITS
--------------------------- ---------------------------
1999 1998 1999 1998
--------- --------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Change in benefit obligation:
Benefit obligation at beginning of year $ 63,841 53,859 $ 8,100 6,600
Service cost 4,937 2,685 838 400
Interest cost 6,464 4,035 1,249 500
Participant contributions -- -- -- 100
Amendments -- 293 -- --
PennzEnergy merger 84,651 -- 27,859 --
Snyder merger 3,100 -- 800 --
Actuarial (loss) gain (3,525) 5,573 600 1,000
Benefits paid (3,899) (2,604) (1,586) (500)
--------- --------- --------- ---------
Benefit obligation at end of year 155,569 63,841 37,860 8,100
--------- --------- --------- ---------
Change in plan assets:
Fair value of plan assets at beginning 41,531 43,136 -- --
of year
Actual return on plan assets 14,808 113 -- --
PennzEnergy merger 104,181 -- -- --
Employer contributions 1,273 886 1,486 400
Participant contributions -- -- 100 100
Benefits paid (3,899) (2,604) (1,586) (500)
--------- --------- --------- ---------
Fair value of plan assets at end of year 157,894 41,531 -- --
--------- --------- --------- ---------
Funded status 2,325 (22,310) (37,860) (8,100)
Unrecognized net actuarial (gain) loss (2,723) 9,130 800 200
Unrecognized prior service cost 1,966 2,322 -- --
Unrecognized net transition (asset) (400) (500) 2,100 2,300
obligation
Other 100 -- 100 100
--------- --------- --------- ---------
Net amount recognized $ 1,268 (11,358) $ (34,860) (5,500)
========= ========= ========= =========
The net amounts recognized in the
consolidated
balance sheets consist of:
Prepaid (accrued) benefit cost $ 1,268 (11,358) $ (34,860) (5,500)
Additional minimum liability (3,110) (2,987) -- --
Intangible asset 1,537 1,808 -- --
Accumulated other comprehensive loss 1,573 1,179 -- --
--------- --------- --------- ---------
Net amount recognized $ 1,268 (11,358) $ (34,860) (5,500)
========= ========= ========= =========
Assumptions:
Discount rate 7.34% 6.69% 7.32% 6.75%
Expected return on plan assets 8.37% 9.35% N/A N/A
Rate of compensation increase 4.88% 4.84% 4.75% 4.75%
</TABLE>
The benefit obligation for the defined benefit pension plans with
benefit obligations in excess of assets was $61.3 million as of December 31,
1999. The plan assets for these plans at December 31, 1999 totaled $39.1
million.
Net periodic benefit cost included the following components:
<TABLE>
<CAPTION>
OTHER POSTRETIREMENT
PENSION BENEFITS BENEFITS
------------------------------------- -----------------------------------
1999 1998 1997 1999 1998 1997
------- ------- ------- ------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 4,937 2,685 2,606 $ 838 400 500
Interest cost 6,464 4,035 3,947 1,249 500 500
Expected return on plan assets (6,900) (3,932) (3,745) -- -- --
Amortization of prior service cost 256 256 194 -- -- --
Amortization of transition -- -- (100) 200 200 200
obligation
Recognized net actuarial (gain) 320 11 59 -- -- --
loss
Curtailment charges (credits) -- -- (2,400) -- -- 300
------- ------- ------- ------- ------- -------
Net periodic benefit cost $ 5,077 3,055 561 $ 2,287 1,100 1,500
======= ======= ======= ======= ======= =======
</TABLE>
For measurement purposes, a 7% annual rate of increase in the per
capita cost of covered health care benefits was assumed in 2000. The rate was
assumed to decrease on a pro-rata basis annually to 5% in the year 2002 and
remain at that
Page 51 of 79 pages
<PAGE> 52
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
level thereafter. Assumed health care cost trend rates have a significant effect
on the amounts reported for the health care plan. A one percentage-point change
in assumed health care cost trend rates would have the following effects:
<TABLE>
<CAPTION>
ONE-PERCENTAGE ONE-PERCENTAGE
POINT INCREASE POINT DECREASE
---------------- -----------------
(IN THOUSANDS)
<S> <C> <C>
Effect on total of service and interest cost components for 1999 $ 224 $ (826)
Effect on year-end 1999 postretirement benefit obligation $ 1,809 (1,116)
</TABLE>
As a result of the PennzEnergy merger, Devon assumed certain
postemployment benefits to former or inactive employees who are not retirees.
These benefits include salary continuance, severance and disability health care
and life insurance which are accounted for under SFAS No. 112, "Employer's
Accounting for Postemployment Benefits." The accrued postemployment benefit
liability was approximately $2.5 million at the end of 1999.
Devon has a 401(k) Incentive Savings Plan which covers all domestic
employees. At its discretion, Devon may match a certain percentage of the
employees' contributions to the plan. The matching percentage is determined
annually by the Board of Directors. Devon's matching contributions to the plan
were $4.3 million, $2.3 million and $2.1 million for the years ended December
31, 1999, 1998 and 1997, respectively.
Devon has defined contribution plans for its Canadian employees. Devon
contributes between 6% and 10% of the employee's base compensation, depending
upon the employee's classification. Such contributions are subject to maximum
amounts allowed under the Income Tax Act (Canada).
Devon also has a savings plan for its Canadian employees. Under the
savings plan, Devon contributes an amount equal to 2% of the base salary of each
employee. The employees may elect to contribute up to 4% of their salary. If
such employee contributions are made, they are matched by additional Devon
contributions.
During the years 1999, 1998 and 1997, Devon's combined contributions to
the Canadian defined contribution plan and the Canadian savings plan were $1.9
million, $1.8 million and $1.2 million, respectively.
As a result of the Santa Fe Snyder merger, Devon also has a savings
plan with respect to certain personnel employed in foreign locations. The plan
is an unsecured creditor of Devon and at December 31, 1999 and 1998, Devon's
liability with respect to the plan totaled $0.4 million and $0.3 million,
respectively.
13. COMMITMENTS AND CONTINGENCIES
Devon is party to various legal actions arising in the normal course of
business. Matters that are probable of unfavorable outcome to Devon and which
can be reasonably estimated are accrued. Such accruals are based on information
known about the matters, Devon's estimates of the outcomes of such matters and
its experience in contesting, litigating and settling similar matters. None of
the actions are believed by management to involve future amounts that would be
material to Devon's financial position or results of operations after
consideration of recorded accruals.
Environmental Matters
Devon is subject to certain laws and regulations relating to
environmental remediation activities associated with past operations, such as
the Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA") and similar state statutes. In response to liabilities associated
with these activities, accruals have been established when reasonable estimates
are possible. Such accruals primarily include estimated costs associated with
remediation. Devon has not used discounting in determining its accrued
liabilities for environmental remediation, and no claims for possible recovery
from third party insurers or other parties related to environmental costs have
been recognized in Devon's consolidated financial statements.
Page 52 of 79 pages
<PAGE> 53
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Devon adjusts the accruals when new remediation responsibilities are discovered
and probable costs become estimable, or when current remediation estimates must
be adjusted to reflect new information.
Certain of Devon's subsidiaries acquired in the PennzEnergy merger are
involved in matters in which it has been alleged that such subsidiaries are
potentially responsible parties ("PRPs") under CERCLA or similar state
legislation with respect to various waste disposal areas owned or operated by
third parties. As of December 31, 1999, Devon's consolidated balance sheet
included $6.7 million of accrued liabilities, reflected in "Other liabilities,"
for environmental remediation. Devon does not currently believe there is a
reasonable possibility of incurring additional material costs in excess of the
current accruals recognized for such environmental remediation activities. With
respect to the sites in which Devon subsidiaries are PRPs, Devon's conclusion is
based in large part on (i) the availability of defenses to liability, including
the availability of the "petroleum exclusion" under CERCLA and similar state
laws, and/or (ii) Devon's current belief that its share of wastes at a
particular site is or will be viewed by the Environmental Protection Agency or
other PRPs as being de minimis. As a result, Devon's monetary exposure is not
expected to be material.
Ramco Dispute
In October 1995, subsidiaries of Devon acquired in the PennzEnergy
merger filed an action, styled Pennzoil Exploration and Production Company, et
al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, in the United States
District Court for the Southern District of Texas, Houston Division, against
Ramco Hazar Energy Limited, formerly known as Ramco Energy Limited (collectively
"Ramco"). The underlying dispute involves Ramco's asserted claim to an interest
in the Karabakh prospect, an oil and gas field located in the territorial waters
of the Azerbaijan Republic in the Caspian Sea. Since the initiation of the
litigation, the operator of the Karabakh prospect determined that the
hydrocarbon accumulation tested by three exploratory wells was not commercial.
The federal suit sought to compel Ramco to arbitrate certain disputes that have
arisen between it and the Devon plaintiffs pursuant to the Federal Arbitration
Act and the Convention on the Recognition and Enforcement of Foreign Arbitral
Awards. After the filing of the federal action, the Devon plaintiffs filed an
Original Petition for Declaration Relief in the 281st Judicial District Court of
Harris County, Texas. The state suit, styled Pennzoil Exploration and Production
Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, which is
expressly conditioned upon a determination in the federal suit that the disputes
between the Devon plaintiffs and Ramco are not subject to arbitration, seeks a
declaration that the Devon plaintiffs have not breached any agreements with
Ramco, and do not owe and/or have not breached any fiduciary or other legal duty
to Ramco including, without limitation, a duty of good faith and fair dealing.
In November 1995, Ramco asserted a counterclaim in the state court action,
asserting breach of contract and breach of fiduciary duties. The counterclaim
seeks a declaratory judgment granting Ramco a participation interest in the
Karabakh prospect, compensatory damages, exemplary damages, attorneys' fees,
court costs and other unspecified relief.
The judge in the federal suit granted in part the plaintiffs' motion to
compel arbitration and ordered arbitration to be held in New York, New York. The
United States Court of Appeals for the Fifth Circuit generally affirmed the
ruling of the judge in the federal suit and the Devon plaintiffs initiated
arbitration. The parties have been engaged in settlement discussions and the
selection of arbitrators has been suspended by agreement of the parties pending
the outcome of the settlement discussions.
Royalty Matters
More than 30 oil companies, including Devon as a result of the
PennzEnergy merger, are involved in disputes in which it is alleged that the oil
companies and related parties have underpaid holders of royalty interests,
overriding royalty interests and working interests in connection with the
production of crude oil. The proceedings include suits in federal court in
Texas, Louisiana, Mississippi and Wyoming (that have been consolidated into one
proceeding in Texas) and in state court in Texas, Utah, Alabama and Louisiana.
Certain parties to the federal litigation have entered into a global settlement
agreement which provides for a conditional nationwide settlement, subject to
opt-outs, of the crude oil royalty, overriding royalty and working
Page 53 of 79 pages
<PAGE> 54
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
interest claims of all members of the settlement class, including claims in the
federal litigation and in numerous other individual and class action cases
pending throughout the United States. The federal court held a fairness hearing
April 5, 1999, and the settlement was approved. The Amended Final Judgment was
entered September 10, 1999. However, certain entities have appealed their
objections to the settlement. Devon is a party to the settlement agreement,
which explicitly refutes an admission of liability, but was entered into to
avoid expensive and protracted litigation.
Also, pending is a separate suit in federal court in Texas alleging
that more than 30 major oil companies, including Devon as a result of the
PennzEnergy merger, underpaid royalties to the United States in connection with
crude oil produced from United States owned and/or controlled lands since 1986.
The claims were filed by private litigants under the federal False Claims Act,
and after investigation, the United States served notice of its intent to
intervene as to certain defendants. Devon has reached an agreement in principle
with the United States and the private litigants to settle the claims made in
the case. Devon believes that it has acted reasonably and paid royalties in good
faith, but has entered into the settlement agreement, which explicitly refutes
an admission of liability, to avoid expensive and protracted litigation. Devon
does not currently believe there is a reasonable possibility of incurring
additional material costs in excess of the liability recognized for such
settlement of the royalty matters.
Maersk Rig Contracts
In December 1997, Pennzoil Venezuela Corporation, S.A. ("PVC"), a
subsidiary of Devon as a result of the PennzEnergy merger, entered into a
contract ("Contract #1") with Maersk Jupiter Drilling, S.A. ("Maersk") for the
provision of a rig for drilling services relative to the anticipated drilling
program associated with Devon's Block 68/79, Lake Maracaibo, Venezuela. The rig
to be provided by Maersk was to be assembled and delivered to the Lake Maracaibo
area and placed in service in October 1998. The term of Contract #1 was to
October 1, 2001. A companion contract ("Contract #2") with Maersk for a second
rig with a similar term for use in conjunction with the Block 70/80 drilling
program was also executed by PVC's working interest partner in that Block.
With execution of Contract #1, construction of the rig destined for
Block 68/79 proceeded until completion thereof. In October 1998, Maersk advised
that it intended to commence mobilization of the rig to Lake Maracaibo. However,
during the period of rig construction, changes had occurred in the scope and
timing of the drilling program anticipated for Block 68/79, resulting in
significant reduction of the need for drilling services originally envisioned in
Contract #1. PVC instructed Maersk to cease mobilization and to stack the rig in
Brownsville, Texas, where it currently remains.
The rig built for Contract #2 was delivered to Lake Maracaibo where it
performed an abbreviated drilling program for both Blocks 68/79 and 70/80. It is
currently stacked in Lake Maracaibo.
While both Contract #1 and #2 provide for early termination, the charge
for such termination is established in each contract as the "Contract Standby
Rate" which is currently estimated at $42,000 per day, per contract, with
certain escalation factors for the balance of the term of each. In 2000, Devon
settled a portion of these commitments. Representatives of PVC and Maersk are
engaged in negotiations relative to the remaining commitments. As of December
31, 1999, Devon's consolidated balance sheet included accrued liabilities,
reflected in "Other liabilities," for the expected cost to terminate/settle both
Contract #1 and Contract #2. This liability was recorded at the time of the
PennzEnergy merger. Devon does not currently believe there is a reasonable
possibility of incurring additional material costs in excess of the liability
recognized for such termination/settlement of both Contract #1 and Contract #2.
Page 54 of 79 pages
<PAGE> 55
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Operating Leases
The following is a schedule by year of future minimum rental payments
required under operating leases that have initial or remaining noncancelable
lease terms in excess of one year as of December 31, 1999:
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, (IN THOUSANDS)
------------------------
<S> <C>
2000 $ 29,521
2001 20,285
2002 12,130
2003 7,462
2004 7,172
Thereafter 27,931
--------
Total minimum lease payments required $104,501
========
</TABLE>
Total rental expense for all operating leases is as follows for the
years ended December 31:
<TABLE>
(IN THOUSANDS)
<S> <C>
1999 $24,204
1998 $18,319
1997 $12,419
</TABLE>
Santa Fe Energy Trust
The Santa Fe Energy Trust (the "Trust") was formed in 1992 to hold 6.3
million Depository Units, each consisting of beneficial ownership of one unit of
undivided interest in the Trust and a $20 face amount beneficial ownership
interest in a $1,000 face amount zero coupon U.S. Treasury obligation maturing
on or about February 15, 2008, when the Trust will be liquidated. The assets of
the Trust consist of certain oil and gas properties conveyed to it by Santa Fe
Snyder.
For any calendar quarter ending on or prior to December 31, 2002, the
Trust will receive additional support payments to the extent that it needs such
payments to distribute $0.39 per Depository Unit per quarter. The source of such
support payments is limited to Devon's remaining royalty interest in certain of
the properties conveyed to the Trust. The aggregate amount of the additional
royalty payments (net of any amounts recouped) is limited to $19.4 million on a
revolving basis. If such support payments are made, certain proceeds otherwise
payable to the Trust in subsequent quarters may be reduced to recoup the amount
of such support payments. Through the end of 1999, the Trust had received
support payments totaling $4.2 million and Santa Fe Snyder had recouped $3.9
million of such payments. In the first quarter of 2000, Santa Fe Snyder recouped
the remaining $0.3 million of support payments.
Depending on various factors, such as sales volumes and prices and the
level of operating costs and capital expenditures incurred, proceeds payable to
the Trust with respect to operations in subsequent quarters may not be
sufficient to make the required quarterly distributions. In such instances,
Devon would be required to make support payments.
At December 31, 1999 and 1998, accounts payable as shown on the
accompanying consolidated balance sheets included $3.4 million and $2.6 million,
respectively, due to the Trust.
14. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES
Under the full cost method of accounting, the net book value of oil and
gas properties, less related deferred income taxes, may not exceed a calculated
"ceiling." The ceiling limitation is the discounted estimated after-tax future
net revenues from proved oil and gas properties. The ceiling is imposed
separately by country. In calculating future net revenues, current prices and
costs are generally held constant indefinitely. The net book value, less
deferred tax liabilities, is compared to the ceiling on a quarterly and annual
basis. Any excess of the net book value, less deferred taxes, is written off as
an expense. An
Page 55 of 79 pages
<PAGE> 56
expense recorded in one period may not be reversed in a subsequent period even
though higher oil and gas prices may have increased the ceiling applicable to
the subsequent period.
During 1999, 1998 and 1997, Devon reduced the carrying value of its oil
and gas properties by $476.1 million, $422.5 million and $641.3 million,
respectively, due to the full cost ceiling limitations. The after-tax effect of
these reductions in 1999, 1998 and 1997 were $309.7 million, $280.8 million and
$408.2 million, respectively.
15. OIL AND GAS OPERATIONS
Costs Incurred
The following tables reflect the costs incurred in oil and gas property
acquisition, exploration, and development activities:
<TABLE>
<CAPTION>
TOTAL
YEAR ENDED DECEMBER 31,
--------------------------------------------
1999 1998 1997
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes $3,002,269 245,467 733,131
Deferred income taxes 131,700 21,382 94,822
---------- ---------- ----------
Total proved, including deferred income
taxes $3,133,969 266,849 827,953
========== ========== ==========
Unproved, excluding deferred income taxes:
Business combinations 83,505 5,278
37,261
Other acquisitions 40,583 55,827 30,275
Deferred income taxes -- 661 6,082
---------- ---------- ----------
Total unproved, including deferred income
taxes $ 124,088 61,766 73,618
========== ========== ==========
Exploration costs $ 157,706 176,014 120,240
Development costs $ 336,126 294,105 328,144
</TABLE>
<TABLE>
<CAPTION>
DOMESTIC
--------------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------------
1999 1998 1997
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes $2,670,237 87,549 196,091
Deferred income taxes 131,700 -- 2,084
---------- ---------- ----------
Total proved, including deferred income
taxes $2,801,937 87,549 198,175
========== ========== ==========
Unproved, excluding deferred income taxes:
Business combinations 81,755 -- --
Other acquisitions 27,728 40,364 22,482
Deferred income taxes -- -- (100)
---------- ---------- ----------
Total unproved, including deferred income
taxes $ 109,483 40,364 22,382
========== ========== ==========
Exploration costs $ 88,171 71,486 66,826
----------
Development costs $ 228,095 149,286 192,743
</TABLE>
<TABLE>
<CAPTION>
CANADA
-----------------------------------
YEAR ENDED DECEMBER 31,
-----------------------------------
1999 1998 1997
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes $29,532 107,818 499,440
Deferred income taxes -- 21,382 92,738
------- ------- -------
Total proved, including deferred income
taxes $29,532 129,200 592,178
======= ======= =======
Unproved, excluding deferred income taxes:
Business combinations -- 5,278 37,261
Other acquisitions 9,155 10,263 5,493
Deferred income taxes -- 661 6,182
------- ------- -------
Total unproved, including deferred income
taxes $ 9,155 16,202 48,936
======= ======= =======
Exploration costs $37,197 49,928 36,314
Development costs $29,811 75,119 82,301
</TABLE>
Page 57 of 79 pages
<PAGE> 57
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
INTERNATIONAL
-------------------------------
YEAR ENDED DECEMBER 31,
------------------------------------
1999 1998 1997
-------- ------ --------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes $302,500 50,100 37,600
Deferred income taxes -- -- --
-------- --------
Total proved, including deferred income
taxes $302,500 50,100 37,600
======== ========
Unproved, excluding deferred income taxes:
Business combinations 1,750 -- --
Other acquisitions 3,700 5,200 2,300
Deferred income taxes -- -- --
-------- --------
Total unproved, including deferred income
taxes $ 5,450 5,200 2,300
========
Exploration costs $ 32,338 54,600 17,100
Development costs $ 78,220 69,700 53,100
</TABLE>
Pursuant to the full cost method of accounting, Devon capitalizes
certain of its general and administrative expenses which are related to property
acquisition, exploration and development activities. Such capitalized expenses,
which are included in the costs shown in the preceding tables, were $28.9
million, $14.8 million and $14.5 million in the years 1999, 1998 and 1997,
respectively.
Due to the tax-free nature of the merger between Santa Fe and Snyder in
May 1999, additional deferred tax liabilities of $131.7 million were allocated
to proved properties. Due to the tax-free nature of the PennzEnergy merger in
August 1999, additional deferred tax liabilities of $338.9 million were recorded
in 1999 and allocated to goodwill.
During 1997, various uncertainties that existed at year-end 1996
regarding the tax basis and liabilities assumed in the acquisition of Kerr-McGee
Corporation's North American onshore oil and gas exploration and production
business and properties ("KMG-NAOS") were resolved. This resulted in an
additional $5.5 million being allocated in 1997 to the proved properties
acquired in the 1996 KMG-NAOS transaction. Of this amount, $3.1 million was for
liabilities assumed and $2.4 million was for additional deferred tax liabilities
created. This additional $5.5 million is included in the preceding table of
costs incurred in 1997. The resolution of the uncertainties also resulted in a
reduction of $0.1 million in 1997 to the deferred tax liabilities originally
allocated in 1996 to the KMG-NAOS unproved properties.
Due to the tax-free nature of the Morrison Transaction, additional
deferred tax liabilities of $128.5 million were recorded in 1997. Of this
amount, $92.7 million was allocated to proved oil and gas properties and $6.2
million was allocated to unproved properties. The remaining amount of $29.6
million was allocated to non-oil and gas properties.
Page 57 of 79 pages
<PAGE> 58
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Results of Operations for Oil and Gas Producing Activities
The following tables include revenues and expenses associated directly
with Devon's oil and gas producing activities. They do not include any
allocation of Devon's interest costs or general corporate overhead and,
therefore, are not necessarily indicative of the contribution to net earnings of
Devon's oil and gas operations. Income tax expense has been calculated by
applying statutory income tax rates to oil and gas sales after deducting costs,
including depreciation, depletion and amortization and after giving effect to
permanent differences.
<TABLE>
<CAPTION>
TOTAL
---------------------------------------------------
YEAR ENDED DECEMBER 31,
---------------------------------------------------
1999 1998 1997
------------ ----------- -----------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $ 1,225,003 660,060 945,904
Production and operating expenses (345,603) (252,700) (297,224)
Depreciation, depletion and amortization (390,117) (230,419) (276,977)
Amortization of goodwill (16,111) -- --
Reduction of carrying value of oil and gas
properties (476,100) (422,500) (641,314)
Income tax (expense) benefit (24,984) 65,515 94,211
----------- ----------- -----------
Results of operations for oil and gas producing
activities $ (27,912) (180,044) (175,400)
=========== =========== ===========
Depreciation, depletion and amortization per
equivalent barrel of production $ 4.46 3.74 4.17
=========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
DOMESTIC
----------------------------------------------------
YEAR ENDED DECEMBER 31,
----------------------------------------------------
1999 1998 1997
--------- --------- ---------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $ 871,202 404,330 699,560
Production and operating expenses (233,609) (151,629) (222,458)
Depreciation, depletion and amortization (293,841) (154,127) (165,691)
Amortization of goodwill (16,106) -- --
Reduction of carrying value of oil and gas
properties (463,700) (301,400) --
Income tax (expense) benefit 37,786 63,630 (109,148)
--------- --------- ---------
Results of operations for oil and gas producing
activities $ (98,268) (139,196) 202,263
========= ========= =========
Depreciation, depletion and amortization per
equivalent
barrel of production $ 4.98 4.41 3.64
========= ========= =========
</TABLE>
<TABLE>
<CAPTION>
CANADA
----------------------------------------------------
YEAR ENDED DECEMBER 31,
----------------------------------------------------
1999 1998 1997
---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $ 193,100 161,030 178,244
Production and operating expenses (51,194) (49,571) (44,366)
Depreciation, depletion and amortization (64,514) (43,392) (91,886)
Reduction of carrying value of oil and gas
properties -- -- (625,514)
Income tax (expense) benefit (37,736) (37,615) 204,159
--------- --------- ---------
Results of operations for oil and gas producing
activities $ 39,656 30,452 (379,363)
========= ========= =========
Depreciation, depletion and amortization per
equivalent barrel of production $ 3.56 2.41 5.64
========= ========= =========
</TABLE>
<TABLE>
<CAPTION>
INTERNATIONAL
----------------------------------------------------
YEAR ENDED DECEMBER 31,
----------------------------------------------------
1999 1998 1997
---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $ 160,701 94,700 68,100
Production and operating expenses (60,800) (51,500) (30,400)
Depreciation, depletion and amortization (31,762) (32,900) (19,400)
Amortization of goodwill (5) -- --
Reduction of carrying value of oil and gas
properties (12,400) (121,100) (15,800)
Income tax (expense) benefit (25,034) 39,500 (800)
--------- --------- ---------
Results of operations for oil and gas producing
activities $ 30,700 (71,300) 1,700
========= ========= =========
Depreciation, depletion and amortization per
equivalent barrel of production $ 3.06 3.78 4.14
========= ========= =========
</TABLE>
Page 58 of 79 pages
<PAGE> 59
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)
The following supplemental unaudited information regarding the oil and
gas activities of Devon is presented pursuant to the disclosure requirements
promulgated by the Securities and Exchange Commission and SFAS No. 69,
"Disclosures About Oil and Gas Producing Activities."
Quantities of Oil and Gas Reserves
Set forth below is a summary of the changes in the net quantities of
crude oil, natural gas and natural gas liquids reserves for each of the three
years ended December 31, 1999. Approximately 98%, 96% and 96%, of the respective
year-end 1999, 1998 and 1997 domestic proved reserves were calculated by the
independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. and
Ryder-Scott Company Petroleum Consultants. The remaining percentages of domestic
reserves are based on Devon's own estimates. All of the year-end 1999 Canadian
proved reserves were calculated by the independent petroleum consultants Paddock
Lindstrom & Associates. All of the year-end 1998 and 1997 Canadian proved
reserves were calculated by the independent petroleum consultants of Paddock
Lindstrom & Associates, AMH Group Ltd. and, for 1997 only, John P. Hunter &
Associates, Ltd. All of the international proved reserves other than Canada as
of December 31, 1999 and 1997 were calculated by the independent petroleum
consultants of Ryder-Scott Company Petroleum Consultants. Of the 1998
international reserves other than Canada, 87% were calculated by Ryder-Scott
Company Petroleum Consultants and 13% were based on Devon's own estimates.
<TABLE>
<CAPTION>
TOTAL
----------------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
---------- ---------- ----------
<S> <C> <C> <C>
Proved reserves as of December 31, 1996 375,355 1,157,719 18,490
Revisions of estimates 9,224 (7,261) 3,595
Extensions and discoveries 42,987 181,608 2,324
Purchase of reserves 29,696 282,592 2,914
Production (32,565) (186,239) (2,842)
Sale of reserves (205,956) (25,215) (3)
---------- ---------- ----------
Proved reserves as of December 31, 1997 218,741 1,403,204 24,478
Revisions of estimates (9,452) (53,209) 2,391
Extensions and discoveries 27,497 174,527 8,652
Purchase of reserves 30,283 164,429 518
Production (25,628) (198,051) (3,054)
Sale of reserves (5,984) (13,906) (306)
---------- ---------- ----------
Proved reserves as of December 31, 1998 235,457 1,476,994 32,679
Revisions of estimates 12,367 6,888 3,254
Extensions and discoveries 12,809 406,157 4,342
Purchase of reserves 272,412 1,417,747 32,795
Production (31,756) (304,203) (5,111)
Sale of reserves (4,572) (53,956) (142)
---------- ---------- ----------
Proved reserves as of December 31, 1999 496,717 2,949,627 67,817
========== ========== ==========
Proved developed reserves as of:
December 31, 1996 307,730 1,030,165 16,263
December 31, 1997 187,758 1,204,874 21,832
December 31, 1998 179,746 1,282,447 19,381
December 31, 1999 301,149 2,500,985 52,102
</TABLE>
page 59 of 79 pages
<PAGE> 60
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
DOMESTIC
----------------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
---------- ---------- ----------
<S> <C> <C> <C>
Proved reserves as of December 31, 1996 331,051 787,461 15,895
Revisions of estimates 4,487 1,581 2,659
Extensions and discoveries 17,294 129,825 2,001
Purchase of reserves 5,026 7,992 16
Production (23,500) (117,520) (2,396)
Sale of reserves (205,956) (25,215) (3)
---------- ---------- ----------
Proved reserves as of December 31, 1997 128,402 784,124 18,172
Revisions of estimates (19,849) 10,919 219
Extensions and discoveries 3,042 108,308 371
Purchase of reserves 1,813 58,655 --
Production (12,257) (121,419) (2,468)
Sale of reserves -- (2,300) --
---------- ---------- ----------
Proved reserves as of December 31, 1998 101,151 838,287 16,294
Revisions of estimates 23,986 35,751 3,407
Extensions and discoveries 1,890 230,059 2,794
Purchase of reserves 142,908 1,399,634 32,709
Production (17,822) (221,061) (4,396)
Sale of reserves (2,689) (8,284) (4)
---------- ---------- ----------
Proved reserves as of December 31, 1999 249,424 2,274,386 50,804
========== ========== ==========
Proved developed reserves as of:
December 31, 1996 273,172 723,007 13,928
December 31, 1997 115,559 646,882 16,789
December 31, 1998 92,931 663,864 14,777
December 31, 1999 214,267 1,959,531 48,237
</TABLE>
<TABLE>
<CAPTION>
CANADA
----------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
-------- -------- --------
<S> <C> <C> <C>
Proved reserves as of December 31, 1996 20,204 343,658 2,495
Revisions of estimates 1,400 (25,266) 13
Extensions and discoveries 1,993 50,583 123
Purchase of reserves 18,270 274,600 2,898
Production (5,728) (60,795) (423)
Sale of reserves -- -- --
-------- -------- --------
Proved reserves as of December 31, 1997 36,139 582,780 5,106
Revisions of estimates 6,283 (70,402) (248)
Extensions and discoveries 655 62,519 81
Purchase of reserves 8,170 105,774 518
Production (6,257) (67,158) (566)
Sale of reserves (5,984) (11,606) (306)
-------- -------- --------
Proved reserves as of December 31, 1998 39,006 601,907 4,585
Revisions of estimates (2,828) (41,044) (268)
Extensions and discoveries 219 52,698 448
Purchase of reserves 2,796 11,890 86
Production (5,178) (73,561) (700)
Sale of reserves (1,883) (45,672) (138)
-------- -------- --------
Proved reserves as of December 31, 1999 32,132 506,218 4,013
======== ======== ========
Proved developed reserves as of
December 31, 1996 19,658 281,058 2,235
December 31, 1997 35,199 522,292 5,043
December 31, 1998 33,215 583,583 4,504
December 31, 1999 29,268 501,376 3,865
</TABLE>
Page 60 of 79 pages
<PAGE> 61
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
INTERNATIONAL
-----------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
-------- -------- ---------
<S> <C> <C> <C>
Proved reserves as of December 31, 1996 24,100 26,600 100
Revisions of estimates 3,337 16,424 923
Extensions and discoveries 23,700 1,200 200
Purchase of reserves 6,400 -- --
Production (3,337) (7,924) (23)
Sale of reserves -- -- --
-------- -------- --------
Proved reserves as of December 31, 1997 54,200 36,300 1,200
Revisions of estimates 4,114 6,274 2,420
Extensions and discoveries 23,800 3,700 8,200
Purchase of reserves 20,300 -- --
Production (7,114) (9,474) (20)
Sale of reserves -- -- --
-------- -------- --------
Proved reserves as of December 31, 1998 95,300 36,800 11,800
Revisions of estimates (8,791) 12,181 115
Extensions and discoveries 10,700 123,400 1,100
Purchase of reserves 126,708 6,223 --
Production (8,756) (9,581) (15)
Sale of reserves -- -- --
-------- -------- --------
Proved reserves as of December 31, 1999 215,161 169,023 13,000
======== ======== ========
Proved developed reserves as of
December 31, 1996 14,900 26,100 100
December 31, 1997 37,000 35,700 --
December 31, 1998 53,600 35,000 100
December 31, 1999 57,614 40 078 --
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows
The accompanying tables reflect the standardized measure of discounted
future net cash flows relating to Devon's interest in proved reserves:
<TABLE>
<CAPTION>
TOTAL
----------------------------------------------------
DECEMBER 31,
----------------------------------------------------
1999 1998 1997
------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows $ 18,494,929 5,114,485 6,296,415
Future costs:
Development (1,506,678) (495,977) (446,661)
Production (6,270,893) (2,091,688) (2,377,359)
Future income tax expense (1,928,398) (196,475) (692,872)
------------ ------------ ------------
Future net cash flows 8,788,960 2,330,345 2,779,523
10% discount to reflect
timing of cash flows (4,020,526) (916,757) (1,099,147)
------------ ------------ ------------
Standardized measure of
discounted future net cash flows $ 4,768,434 1,413,588 1,680,376
============ ============ ============
</TABLE>
<TABLE>
<CAPTION>
DOMESTIC
----------------------------------------------------
DECEMBER 31,
----------------------------------------------------
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
Future cash inflows $ 11,362,918 2,718,030 3,958,402
Future costs:
Development (750,497) (162,715) (201,450)
Production (3,894,271) (1,123,932) (1,463,530)
Future income tax expense (1,071,699) (117,912) (478,080)
------------ ------------ ------------
Future net cash flows 5,646,451 1,313,471 1,815,342
10% discount to reflect timing of
cash flows (2,335,312) (503,689) (740,463)
------------ ------------ ------------
Standardized measure of
discounted future net cash flows $ 3,311,139 809,782 1,074,879
============ ============ ============
</TABLE>
Page 61 of 79 pages
<PAGE> 62
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
CANADA
-------------------------------------------------
DECEMBER 31,
-------------------------------------------------
1999 1998 1997
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows $ 1,666,358 1,333,655 1,424,213
Future costs:
Development (66,631) (85,362) (75,411)
Production (514,825) (491,256) (542,329)
Future income tax expense (204,290) (39,563) (130,092)
----------- ----------- -----------
Future net cash flows 880,612 717,474 676,381
10% discount to reflect timing
of cash flows (320,722) (279,568) (239,684)
----------- ----------- -----------
Standardized measure of
discounted future net cash flows $ 559,890 437,906 436,697
=========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
INTERNATIONAL
-------------------------------------------------
DECEMBER 31,
-------------------------------------------------
1999 1998 1997
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows $ 5,465,653 1,062,800 913,800
Future costs:
Development (689,550) (247,900) (169,800)
Production (1,861,797) (476,500) (371,500)
Future income tax expense (652,409) (39,000) (84,700)
----------- ----------- -----------
Future net cash flows 2,261,897 299,400 287,800
10% discount to reflect
timing of cash flows (1,364,492) (133,500) (119,000)
----------- ----------- -----------
Standardized measure of
discounted future net cash flow $ 897,405 165,900 168,800
=========== =========== ===========
</TABLE>
Future cash inflows are computed by applying year-end prices (averaging
$22.51 per barrel of oil, adjusted for transportation and other charges, $2.00
per Mcf of gas and $16.59 per barrel of natural gas liquids at December 31,
1999) to the year-end quantities of proved reserves, except in those instances
where fixed and determinable price changes are provided by contractual
arrangements in existence at year-end.
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing proved oil and gas
reserves at the end of the year, based on year-end costs and assuming
continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate
statutory tax rates to the future pre-tax net cash flows relating to proved
reserves, net of the tax basis of the properties involved. The future income tax
expenses give effect to permanent differences and tax credits, but do not
reflect the impact of future operations.
Page 62 of 79 pages
<PAGE> 63
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows
Principal changes in the standardized measure of discounted future net
cash flows attributable to Devon's proved reserves are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1999 1998 1997
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning balance $ 1,413,588 1,680,676 2,932,074
Sales of oil, gas and natural gas
liquids, net of production costs (879,400) (407,360) (648,680)
Net changes in prices and
production costs 1,737,640 (743,193) (1,393,034)
Extensions, discoveries, and
improved recovery, net of future
development costs 315,932 280,414 270,098
Purchase of reserves, net of future
development costs 2,881,881 223,055 302,373
Development costs incurred during
the period which reduced future
development costs 233,880 284,999 479,068
Revisions of quantity estimates (62,821) (181,314) 42,549
Sales of reserves in place (77,707) (36,565) (969,895)
Accretion of discount 146,904 201,465 291,401
Net change in income taxes (929,237) 305,317 739,184
Other, primarily changes in timing (12,226) (193,906) (364,462)
----------- ----------- -----------
Ending balance $ 4,768,434 1,413,588 1,680,676
=========== =========== ===========
</TABLE>
17. SEGMENT INFORMATION
Devon manages its business by country. As such, Devon identifies its
segments based on geographic areas. Devon has three segments: its operations in
the U.S., its operations in Canada, and its international operations outside of
North America. Substantially all of these segments' operations involve oil and
gas producing activities. Certain information regarding such activities for each
segment is included in Notes 15 and 16.
Following is certain financial information regarding Devon's segments
for 1999, 1998 and 1997. The revenues reported are all from external customers.
Page 63 of 79 pages
<PAGE> 64
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
17. SEGMENT INFORMATION (CONTINUED)
<TABLE>
<CAPTION>
U.S. CANADA INTERNATIONAL TOTAL
----------- ----------- ------------- -----------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
AS OF DECEMBER 31, 1999:
Current assets $ 391,328 69,279 129,687 590,294
Property and equipment, net of accumulated
depreciation, depletion and amortization 3,424,415 467,465 531,540 4,423,420
Other assets 944,958 98 137,590 1,082,646
----------- ----------- ----------- -----------
Total assets $ 4,760,701 536,842 798,817 6,096,360
=========== =========== =========== ===========
Current liabilities 356,944 44,989 65,411 467,344
Long-term debt 2,077,180 339,341 -- 2,416,521
Deferred tax liabilities (assets) 340,514 1,733 (18,182) 324,065
Other liabilities 317,706 3,098 46,306 367,110
Stockholders' equity 1,668,357 147,681 705,282 2,521,320
----------- ----------- ----------- -----------
Total liabilities and stockholders' equity $ 4,760,701 536,842 798,817 6,096,360
=========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 1999:
REVENUES
Oil sales $ 329,162 76,171 148,501 553,834
Gas sales 484,430 106,895 11,900 603,225
Natural gas liquids sales 57,610 10,034 300 67,944
Other 14,574 4,652 1,370 20,596
----------- ----------- ----------- -----------
Total revenues 885,776 197,752 162,071 1,245,599
----------- ----------- ----------- -----------
COSTS AND EXPENSES
Lease operating expenses 193,017 49,831 60,400 303,248
Production taxes 40,592 1,363 400 42,355
Depreciation, depletion and amortization of
property and equipment 309,292 65,176 31,907 406,375
Amortization of goodwill 16,106 -- 5 16,111
General and administrative expenses 68,807 12,189 (351) 80,645
Expenses related to mergers 16,800 -- -- 16,800
Interest expense 83,679 24,945 989 109,613
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt -- (13,154) -- (13,154)
Distributions on preferred securities of
subsidiary trust 6,884 -- -- 6,884
Reduction of carrying value of oil and gas
properties 463,700 -- 12,400 476,100
----------- ----------- ----------- -----------
Total costs and expenses 1,198,877 140,350 105,750 1,444,977
----------- ----------- ----------- -----------
Earnings (loss) before income tax expense (benefit)
and extraordinary item (313,101) 57,402 56,321 (199,378)
INCOME TAX EXPENSE (BENEFIT)
Current 15.348 2,908 4,800 23,056
Deferred (119,881) 26,654 20,737 (72,490)
----------- ----------- ----------- -----------
Total income tax expense (benefit) (104,533) 29,562 25,537 (49,434)
----------- ----------- ----------- -----------
Net earnings (loss) before extraordinary item (208,568) 27,840 30,784 (149,944)
Extraordinary loss (4,200) -- -- (4,200)
----------- ----------- ----------- -----------
Net earnings (loss) $ (212,768) 27,840 30,784 (154,144)
=========== =========== =========== ===========
Capital expenditures $ 686,669 91,853 104,898 883,420
=========== =========== =========== ===========
</TABLE>
Page 64 of 79 pages
<PAGE> 65
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
17. SEGMENT INFORMATION (CONTINUED)
<TABLE>
<CAPTION>
U.S. CANADA INTERNATIONAL TOTAL
----------- ----------- ------------- -----------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
AS OF DECEMBER 31, 1998:
Current assets $ 90,698 53,550 82,400 226,648
Property and equipment, net of accumulated
depreciation, depletion and amortization 991,040 465,488 167,000 1,623,528
Deferred tax assets (liabilities) (36,093) 24,174 66,300 54,381
-----------
Other assets 17,126 1,454 7,400 25,980
----------- ----------- ----------- -----------
Total assets $ 1,062,771 544,666 323,100 1,930,537
=========== =========== =========== ===========
Current liabilities 119,132 55,624 45,100 219,856
Long-term debt 365,600 370,271 -- 735,871
Other liabilities 67,487 5,760 2,300 75,547
TCP Securities 149,500 -- -- 149,500
Stockholders' equity 361,052 113,011 275,700 749,763
----------- ----------- ----------- -----------
Total liabilities and stockholders' equity $ 1,062,771 544,666 323,100 1,930,537
=========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 1998:
REVENUES
Oil sales $ 151,386 73,338 82,200 306,924
Gas sales 233,073 83,071 12,300 328,444
Natural gas liquids sales 19,871 4,621 200 24,692
Other 9,294 13,754 1,200 24,248
----------- ----------- ----------- -----------
Total revenues 413,624 174,784 95,900 684,308
----------- ----------- ----------- -----------
COSTS AND EXPENSES
Lease operating expenses 130,774 47,910 51,200 229,884
Production taxes 20,855 1,661 300 22,816
Depreciation, depletion and amortization 165,654 44,590 32,900 243,144
General and administrative expenses 35,752 12,502 (2,800) 45,454
Merger related expenses 3,064 10,085 -- 13,149
Interest expense 20,558 21,974 1,000 43,532
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt -- 16,104 -- 16,104
Distributions on preferred securities of 9,717 -- -- 9,717
subsidiary trust
Reduction of carrying value of oil and gas 301,400 -- 121,100 422,500
----------- ----------- ----------- -----------
properties
Total costs and expenses 687,774 154,826 203,700 1,046,300
----------- ----------- ----------- -----------
Earnings (loss) before income tax expense (benefit) (274,150) 19,958 (107,800) (361,992)
INCOME TAX EXPENSE (BENEFIT)
Current (7,588) 1,975 1,900 (3,713)
Deferred (92,360) 11,166 (41,200) (122,394)
----------- ----------- ----------- -----------
Total income tax expense (benefit) (99,948) 13,141 (39,300) (126,107)
----------- ----------- ----------- -----------
Net earnings (loss) $ (174,202) 6,817 (68,500) (235,885)
=========== =========== =========== ===========
Capital expenditures $ 347,634 205,178 160,000 712,812
=========== =========== =========== ===========
</TABLE>
Page 65 of 79 pages
<PAGE> 66
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
17. SEGMENT INFORMATION (CONTINUED)
<TABLE>
<CAPTION>
U.S. CANADA INTERNATIONAL TOTAL
---------- ---------- ------------- ----------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31, 1997:
REVENUES
<S> <C> <C> <C> <C>
Oil sales $ 402,704 92,221 57,600 552,525
Gas sales 266,918 80,441 10,200 357,559
Natural gas liquids sales 29,938 5,582 300 35,820
Other 4,674 42,581 1,000 48,255
---------- ---------- ---------- ----------
Total revenues 704,234 220,825 69,100 994,159
---------- ---------- ---------- ----------
COSTS AND EXPENSES
Lease operating expenses 193,412 42,785 30,000 266,197
Production taxes 29,046 1,581 400 31,027
Depreciation, depletion and amortization 173,544 93,164 19,000 285,708
General and administrative expenses 42,381 13,900 (3,200) 53,081
Interest expense 17,669 18,519 5,300 41,488
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt -- 5,860 -- 5,860
Distributions on preferred securities of 9,717 -- -- 9,717
subsidiary trust
Reduction of carrying value of oil and gas -- 625,514 15,800 641,314
---------- ---------- ---------- ----------
properties
Total costs and expenses 465,769 801,323 67,300 1,334,392
---------- ---------- ---------- ----------
Earnings (loss) before income tax expense (benefit)
and minority interest 238,465 (580,498) 1,800 (340,233)
INCOME TAX EXPENSE (BENEFIT)
Current 24,880 5,677 5,200 35,757
Deferred 62,503 (219,302) (5,700) (162,499)
---------- ---------- ---------- ----------
Total income tax expense (benefit) 87,383 (213,625) (500) (126,742)
---------- ---------- ---------- ----------
Net earnings (loss) before minority interest 151,082 (366,873) 2,300 (213,491)
Minority interest (4,700) -- -- (4,700)
---------- ---------- ---------- ----------
Net earnings (loss) $ 146,382 (366,873) 2,300 (218,191)
========== ========== ========== ==========
Capital expenditures $ 450,989 167,302 108,600 726,891
========== ========== ========== ==========
</TABLE>
18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Following is a summary of the unaudited interim results of operations
for the years ended December 31, 1999 and 1998.
<TABLE>
<CAPTION>
1999
-------------------------------------------------------------------------------
FIRST SECOND THIRD FOURTH FULL
QUARTER QUARTER QUARTER QUARTER YEAR
---------- ------- ------- ------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Oil, gas and natural gas liquids
sales $ 153,293 213,993 371,141 486,576 1,225,003
Total revenues $ 155,866 216,912 376,551 496,270 1,245,599
Net earnings (loss) $ 6,580 (286,491) 50,852 74,915 (154,144)
Net earnings (loss) per common share:
Basic $ 0.09 (3.55) 0.50 0.59 (1.68)
Diluted $ 0.09 (3.55) 0.48 0.57 (1.68)
</TABLE>
<TABLE>
<CAPTION>
1998
-----------------------------------------------------------------------------
FIRST SECOND THIRD FOURTH FULL
QUARTER QUARTER QUARTER QUARTER YEAR
--------- ------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Oil, gas and natural gas liquids
sales $ 166,908 171,107 166,369 155,676 660,060
Total revenues $ 171,437 183,375 169,070 160,426 684,308
Net earnings (loss) $ (675) (4,127) (82,495) (148,588) (235,885)
Net earnings (loss) per common
share:
Basic $ (0.01) (0.06) (1.16) (2.10) (3.32)
Diluted $ (0.01) (0.06) (1.16) (2.10) (3.32)
</TABLE>
Page 66 of 79 pages
<PAGE> 67
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
The second and fourth quarters of 1999 include pre-tax reductions of
the carrying value of oil and gas properties of $463.8 million and $12.3
million, respectively. The after-tax effects of these quarterly reductions were
$301.7 million and $8.0 million, respectively. The per share effect of these
quarterly reductions were $3.74 and $0.06, respectively. The second quarter of
1999 includes $16.8 million of expenses incurred in connection with the Snyder
merger. The after-tax effect of these expenses was $10.9 million, or $0.14 per
share.
The first, second, third and fourth quarters of 1998 include pre-tax
reductions of the carrying value of oil and gas properties of $35.7 million,
$38.1 million, $126.9 million and $221.8 million, respectively. The after-tax
effects of these quarterly reductions were $23.3 million, $24.8 million, $88.0
million and $144.7 million, respectively. The per share effect of these
quarterly reductions were $0.36, $0.38, $1.24 and $2.24, respectively. The
fourth quarter of 1998 includes $13.1 million of costs incurred in connection
with the Northstar Combination. The after-tax effect of these expenses was $9.7
million, or $0.14 per share.
Page 67 of 79 pages
<PAGE> 68
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS
(c) Exhibits
12 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends
23.1 Consent of KPMG LLP
23.2 Consent of Deloitte & Touche LLP
23.3 Consent of PricewaterhouseCoopers LLP
23.4 Consent of LaRoche Petroleum Consultants, Ltd.
23.5 Consent of AMH Group, Ltd.
23.6 Consent of Paddock Lindstrom & Associates Ltd.
23.7 Consent of Ryder Scott Company, L.P.
23.8 Consent of John P. Hunter & Associates Ltd.
23.9 Consent of Ryder Scott Company, L.P.
27 Financial Data Schedule (filed electronically only)
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned hereto duly authorized.
DEVON ENERGY CORPORATION
By: /s/ Danny J. Heatly
Vice President - Accounting
Date: November 13, 2000
Page 68 of 79 pages
<PAGE> 69
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C>
12 Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividends
23.1 Consent of KPMG LLP
23.2 Consent of Deloitte & Touche LLP
23.3 Consent of PricewaterhouseCoopers LLP
23.4 Consent of LaRoche Petroleum Consultants, Ltd.
23.5 Consent of AMH Group, Ltd.
23.6 Consent of Paddock Lindstrom & Associates Ltd.
23.7 Consent of Ryder Scott Company, L.P.
23.8 Consent of John P. Hunter & Associates Ltd.
23.9 Consent of Ryder Scott Company, L.P.
27 Financial Data Schedule (filed electronically only)
</TABLE>
Page 69 of 79 pages
