UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K/A
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 000-30176
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
DELAWARE 73-1567067
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
20 NORTH BROADWAY, SUITE 1500
OKLAHOMA CITY, OKLAHOMA 73102-8260
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (405) 235-3611
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
Common Stock, par value $.10 per share American Stock Exchange
4.9% Convertible Debentures, due 2008 The New York Stock Exchange
4.95% Convertible Debentures, due 2008 The New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [x] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [x]
The aggregate market value of the voting stock held by non-affiliates
of the Registrant as of March 13, 2001, was $7,974,236,970. At such date
126,320,151 shares of common stock and 2,817,992 exchangeable shares of Devon's
wholly-owned subsidiary, Northstar Energy Corporation, were outstanding. Each
exchangeable share is exchangeable for one share of Devon common stock.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2001 annual meeting of stockholders - Part III
1
PART I
ITEM 1. BUSINESS
The "International Regulations" section under Item 1 has been replaced in its
entirety with the following:
INTERNATIONAL REGULATIONS
The oil and gas industry is subject to various types of regulation
throughout the world. Legislation affecting the oil and gas industry has been
pervasive and is under constant review for amendment or expansion. Pursuant to
such legislation, government agencies have issued extensive rules and
regulations binding on the oil and gas industry and its individual members, some
of which carry substantial penalties for failure to comply. Such laws and
regulations have a significant impact on oil and gas drilling and production
activities, increase the cost of doing business and, consequently, affect
profitability. Inasmuch as new legislation affecting the oil and gas industry is
commonplace and existing laws and regulations are frequently amended or
reinterpreted, Devon is unable to predict the future cost or impact of complying
with such laws and regulations. The following are significant areas of
regulation.
EXPLORATION AND PRODUCTION. Devon's oil and gas concessions and permits
are granted by host governments and administered by various foreign government
agencies. Such foreign governments require compliance with detailed regulations
and orders which regulate, among other matters, drilling and operations on areas
covered by concessions and permits and calculation and disbursement of royalty
payments, taxes and minimum investments to the government.
Regulation includes requiring permits for the drilling of wells;
maintaining bonding requirements in order to drill or operate wells;
implementing spill prevention plans; submitting notification and receiving
permits relating to the presence, use and release of certain materials
incidental to oil and gas operations; and regulating the location of wells, the
method of drilling and casing wells, the use, transportation, storage and
disposal of fluids and materials used in connection with drilling and production
activities, surface usage and the restoration of properties upon which wells
have been drilled, the plugging and abandoning of wells and the transporting of
production. Devon's operations are also subject to regulations which may limit
the number of wells or the locations at which Devon can drill.
ENVIRONMENTAL REGULATIONS. Various government laws and regulations
concerning the discharge of incidental materials into the environment, the
generation, storage, transportation and disposal of contaminants or otherwise
relating to the protection of public health, natural resources, wildlife and the
environment, affect Devon's exploration, development and production operations
and the costs attendant thereto. In general, this consists of preparing
Environmental Impact Assessments in order to receive required environmental
permits to conduct drilling or construction activities. Such regulations also
typically include requirements to develop emergency response plans, waste
management plans, and spill contingency plans. In some countries, the
application of worldwide standards, such as ISO 14000 governing
2
Environmental Management Systems, are required to be implemented for
international oil and gas operations.
Brazil has stringent environmental laws. The basic federal law
governing the environment is Law No. 9.605 of February 12, 1998, which set up
areas of conservation that receive federal protection. The governmental
environmental agency is IBAMA, which has significant enforcement powers.
Environmental Impact Studies are required to determine the impact of activities
on the environment and provide ways to avoid or diminish negative effects of the
project on the environment. CONAMA Resolution 23 of December 7, 1994 established
licensing criteria for activities related to drilling and production. Prior to
commencement of exploration activities, IBAMA or a state environmental agency
inspects the equipment to be used and must grant a license; the inspection and
grant of the license may cause delays in start-up of operations. In addition to
federal regulations, state and local agencies may have additional jurisdiction.
Damage to the environment results in strict liability to the holder of the
Concession. Sanctions for violations can be civil, criminal and administrative
in nature.
GOVERNMENT TAKES AND TAXATION
Foreign governments have been evaluating in recent years in and, in
some cases, promulgating new rules and regulations regarding royalty payment
obligations and taxes.
In Brazil there are numerous taxes imposed by federal, state and
municipal governments on services and equipment, which require extensive record
keeping and withholdings. Among the most significant are the following: Law No.
9.779 of 1999 extended the tax for income legal entities earn with the rendering
of services, technical assistance and administrative services to 25%. There is a
Value Added Sales Tax (ICMS) ranging between 7% and 25% and a municipal service
tax (ISS), typically paid in the place of performance, of about 5%. Excise tax
(IPI) is paid on all goods manufactured or imported into Brazil that average
about 10% (see exception for imports of equipment for petroleum activities
above). There are "social contribution" taxes for funding Brazil's extensive
social welfare programs. COFINS, a social contribution tax charged on gross
receipts, including financial and currency transactions and investments is 3%,
and PIS, to fund the unemployment insurance program, is financed by the employer
at 0.65% of its gross monthly receipts. Additionally, there is a severance fund
contribution (FGTS). A banking tax ("CPMF") on the debit of funds from an
account is charges at 0.30%.
In Argentina Competitiveness Law No. 25,413 amended by Law 25,453
created a new tax applicable on bank credits and debits. The tax is applicable
on (1) credits and debits on current accounts in financial entities subject to
the Financial Entities Law; (2) the operations carried out by financial entities
subject to the Financial Entities Law where the person/entity ordering the
financial operation or the beneficiaries do not use the current accounts
mentioned above, and (3) the movement or handing over of funds (whether owned or
belonging to third parties), by any person or entity. The General Tax Rate
(subject to certain tax credits) is 0.6% in the case of debits and credits. In
the cases described in points 2 and 3 above, it will be deemed that said
financial operations replace the corresponding debits and credits and the tax
rate will be doubled.
3
GOVERNMENT AUTHORIZATIONS AND FILINGS.
Host country law and regulations in certain cases requires prior
approval by the national government of any acquisition of concession and permits
granting hydrocarbon rights and allowing petroleum operations to be conducted.
In Argentina, Section 72 of Hydrocarbons Law 17,319 provides that
permits and concessions granted under this law may be assigned with the prior
authorization of the Government to assignees who meet the conditions required to
be a concession holder. Such prior approval of the Government would be required
if the permits and concessions held by Devon were transferred directly to a
purchaser as assets. However, according to the past practice of the Secretariat
of Energy, indirect transfers of permits and concessions by sale of the stock
have not been subject to the prior approval of the Government.
Subject to certain exemptions, Section 8 of Antitrust Law 25,156 as
amended by Section 2 of National Executive Branch Decree No. 396/01, provides
that the purchase of the property or any other right to shares or capital
participations must be notified to the Comision Nacional de Defensa de la
Competencia before execution or within a week after the transaction is closed,
where the total volume of business of the participating companies exceeds US
$200,000,000 in Argentina.
ITEM 2. PROPERTIES
OPERATION OF PROPERTIES
The "Gulf Division" section under Item 2. Properties, Operation of Properties
has been replaced in its entirety with the following:
GULF DIVISION
Devon is one of the 10 largest oil and gas producers in the offshore
Gulf of Mexico. The Santa Fe Snyder merger nearly doubled Devon's asset base in
the Gulf. The offshore Gulf is a prolific producing area that provides
approximately 25% of the natural gas produced in the United States. The Gulf is
comprised of two major operating areas, as defined by water depth. The shallow
area, in water depths up to 600 feet, is known as the "shelf." Devon has a
substantial infrastructure of platforms and production facilities on the shelf,
where natural gas wells are known for providing high initial flow rates and
quick investment returns. Devon holds approximately 650,000 net acres on the
shelf, about 50% of which is developed.
Devon is especially optimistic about the application of Four Component
(4C) 3D seismic for both exploration and exploitation. In the West Cameron South
Area, Offshore Louisiana, Devon underwrote the acquisition and processing of
over 40 blocks of 4C 3D seismic due to a large producing and exploratory acreage
position. A similar survey is underway in the Eugene Island area. Significant
advantages accrue when oil and gas prospects and potential infield drill sites
are evaluated with both conventional compressional wave (P-wave) seismic data
and converted shear wave (C-wave) seismic data rather than with P-wave data
only. The combination of P-wave and C-wave seismic data provides geologic
insights that cannot be provided by
4
conventional P-wave data alone. The structural picture beneath shallow gas
fields becomes very clear using 4-C data sets. Salt imaging is also clarified
using this technique which is extremely important in the deep Eugene Island
area.
One of the more important characteristics of C-wave data is that it
will not respond to fluid in the pore spaces of rock and responds to the matrix
of the rock. This was tested by Devon initially, by recording 2D 4C seismic over
known shallow gas reservoirs for the response to insitu hydrocarbon. The P-wave
and C-wave data were compared. The gross distortion to the P-wave from the
shallow gas was not seen on the C-wave data. The large velocity pull down was
not on the C-wave data and the deep structural configuration was evident. The
bright spots associated with these gas accumulations on the P-wave data were not
evident on the C-wave data making for an excellent discriminator for true
hydrocarbon anomalies.
This approach is currently being employed by Devon. An exploitation
well is planned for the fourth quarter of this year in the WC-560 field area.
The A-8 well will be drilled testing a P-wave amplitude in the D. Brouweri
section that is not seen on the C-wave data. This is using the shear waves as a
discriminator and indicating a probable 25 BCF gas accumulation.
Devon is actively developing other aspects of this cutting edge
technology. The stratigraphic information that is contained in C-wave data needs
to be unlocked for a powerful exploration tool, and the depth to geopressured
formations can be interpreted more readily from inverted C-wave data.
While the shelf is a very mature area, the deep water of the Gulf is
believed to hold some of the largest remaining undiscovered reserves in North
America. Devon holds about 400,000 net acres in the deep water, of which about
90% is unexplored. Because costs are much higher to explore in the deep water
than on the shelf, the company's strategy is to move cautiously into deep water
drilling. Devon expects to participate in three to four deep water exploratory
wells per year.
The Gulf Division also holds about 300,000 net acres onshore in south
Texas and south Louisiana. About 80% of that acreage is developed for oil and
gas production. Last year was a turnaround year for the Gulf Division onshore.
Most of the onshore acreage was acquired in Devon's merger with PennzEnergy in
1999. As PennzEnergy was focused elsewhere, this acreage had received little
attention in recent years. An active onshore drilling program in 2000 resulted
in 14 net wells. This year we will more than double that number to a planned 38
net wells. A notable discovery in 2000 was in the Patterson Field in south
Louisiana. Devon's Zenor A-16 (50% working interest) was tested at over 20
million cubic feet of natural gas per day.
5
ITEM 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
1998 through 2000. Reference is made to "Item 6. Selected Financial Data" and
"Item 8. Financial Statements and Supplementary Data."
The "Overview" and "Results of Operations" sections under Item 7 have been
replaced in its entirety with the following:
OVERVIEW
On May 25, 2000, Devon and Santa Fe Snyder Corporation announced their
intent to merge. The transaction closed on August 29, 2000. The merger with
Santa Fe Snyder was the largest transaction in Devon's history. As a result of
the transaction, Devon issued approximately 40.6 million shares of common stock
and assumed $730.9 million of long-term debt and $492.7 million of other
liabilities. The merger increased Devon's proved reserves by 386.3 million
barrels, or 58%, and the company's undeveloped leasehold by 16 million acres, or
99%.
The merger with Santa Fe Snyder significantly expanded Devon's
operations. However, another significant contributing factor to Devon's growth
over the last three years was the company's 1999 acquisition of PennzEnergy
Company ("PennzEnergy"). The acquisition of PennzEnergy added 396 million Boe of
reserves, 13 million net acres of undeveloped leasehold and $3.2 billion of
assets to Devon's balance sheet. In exchange, 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 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 December 10, 1998, Devon and Northstar Energy Corporation
("Northstar") completed their merger. The 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.
In addition to the mergers and acquisitions, Devon's exploration and
development efforts have also been significant contributors to Devon's growth.
In 1998 and 1999, before the merger with Santa Fe Snyder, Devon spent
approximately $0.5 billion in its exploration, drilling and development efforts.
These costs included drilling 1,233 wells, of which 1,137 were completed as
producers. In 2000, Devon and Santa Fe Snyder combined spent $0.9 billion in its
exploration, drilling and development efforts. These costs included drilling
1,328 wells, of which 1,261 were completed as producers.
Devon's merger with Santa Fe Snyder was accounted for under the
pooling-of-interests method of accounting for business combinations.
Accordingly, Devon's prior years' results have
6
been restated to combine such results with those of Santa Fe Snyder for all
years presented. Thus, the three-year comparisons of various production, revenue
and expense items presented later in this section are shown as if Devon and
Santa Fe Snyder had been combined for all such periods. Although this is
consistent with the financial presentation of the merger, it disguises the
substantial changes in Devon's operations that have occurred as a result of that
transaction.
To present the effects that Devon's merger with Santa Fe Snyder, the
acquisition of PennzEnergy and Devon's drilling and development activities have
had on operations during the last three years, the following statistics have
been developed. This data assumes that Devon's merger with Santa Fe Snyder was
closed at the beginning of 2000, but that prior year results were not restated.
Thus, it compares Devon's 2000 results, including Santa Fe Snyder, to those of
1998 for Devon only, without Santa Fe Snyder. Such comparison yields the
following fluctuations:
o Combined oil, gas and NGL production increased 85.0 million Boe, or 236%.
o Average combined price of oil, gas and NGL increased by $11.68 per Boe, or
108%.
o Total revenues increased $2.3 billion, or 599%.
o Net cash provided by operating activities increased $1.4 billion, or 745%.
Cash margin increased $1.6 billion, or 853%.
o Net earnings increased $790.6 million.
o Earnings per share increased to $5.50 per diluted share from a loss of $1.25
per diluted share in 1998.
During 2000, Devon marked its twelfth anniversary as a public company.
While Devon has consistently increased production over this twelve-year period,
volatility in oil and gas prices has resulted in considerable variability in
earnings and cash flows. Prices for oil, natural gas and NGL 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 initial 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 twelve-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.
7
RESULTS OF OPERATIONS
The following discussion of Devon's results of operations from 1998
through 2000 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 $706.2 million in 1998 to $2.8
billion in 2000. In each of these three years, oil, gas and NGL sales accounted
for over 96% of total revenues.
Changes in oil, gas and NGL production, prices and revenues from 1998
to 2000 are shown in the following tables. (Unless otherwise stated, all dollar
amounts are expressed in U.S. dollars.)
TOTAL
---------------------------------------------------------------------
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
----------- ------- --------- ------- -------
(ABSOLUTE AMOUNTS IN THOUSANDS)
PRODUCTION
Oil (MBbls)....................... 42,561 +34% 31,756 +24% 25,628
Gas (MMcf)........................ 426,146 +40% 304,203 +54% 198,051
NGL (MBbls)....................... 7,400 +45% 5,111 +67% 3,054
Oil, gas and NGL (MBoe)........... 120,985 +38% 87,568 +42% 61,691
REVENUES
Per Unit of Production:
Oil (per Bbl)................... $ 25.35 +43% 17.67 +46% 12.10
Gas (per Mcf)................... $ 3.49 +69% 2.06 +18% 1.75
NGL (per Bbl)................... $ 20.87 +57% 13.30 +64% 8.09
Oil, gas and NGL (per Boe)...... $ 22.47 +57% 14.35 +30% 11.05
Absolute:
Oil............................. $ 1,078,759 +92% 561,018 +81% 309,990
Gas............................. $ 1,485,221 +137% 627,869 +81% 347,273
NGL............................. $ 154,465 +127% 67,985 +175% 24,715
----------- --------- -------
Oil, gas and NGL................ $ 2,718,445 +116% 1,256,872 +84% 681,978
=========== ========= =======
8
DOMESTIC
---------------------------------------------------------------------
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
----------- ------- --------- ------- -------
(ABSOLUTE AMOUNTS IN THOUSANDS)
PRODUCTION
Oil (MBbls)....................... 28,562 +60% 17,822 +45% 12,257
Gas (MMcf)........................ 355,087 +61% 221,061 +82% 121,419
NGL (MBbls)....................... 6,702 +52% 4,396 +78% 2,468
Oil, gas and NGL (MBoe)........... 94,445 +60% 59,062 +69% 34,962
REVENUES
Per Unit of Production:
Oil (per Bbl)................... $ 25.45 +37% 18.64 +50% 12.43
Gas (per Mcf)................... $ 3.67 +62% 2.27 +12% 2.02
NGL (per Bbl)................... $ 20.30 +55% 13.11 +63% 8.05
Oil, gas and NGL (per Boe)...... $ 22.95 +52% 15.10 +26% 11.94
Absolute:
Oil............................. $ 726,897 +119% 332,219 +118% 152,297
Gas............................. $ 1,304,626 +160% 501,841 +105% 245,145
NGL............................. $ 136,048 +136% 57,610 +190% 19,871
----------- ------- -------
Oil, gas and NGL................ $ 2,167,571 +143% 891,670 +114% 417,313
=========== ======= =======
CANADA
---------------------------------------------------------------------
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
----------- ------- --------- ------- -------
(ABSOLUTE AMOUNTS IN THOUSANDS)
PRODUCTION
Oil (MBbls)....................... 4,760 (8)% 5,178 (17)% 6,257
Gas (MMcf)........................ 62,284 (15)% 73,561 +10% 67,158
NGL (MBbls)....................... 682 (3)% 700 +24% 566
Oil, gas and NGL (MBoe)........... 15,823 (13)% 18,138 +1% 18,016
REVENUES
Per Unit of Production:
Oil (per Bbl)................... $ 24.46 +58% 15.51 +29% 12.07
Gas (per Mcf)................... $ 2.71 +75% 1.55 +16% 1.34
NGL (per Bbl)................... $ 26.51 +84% 14.39 +75% 8.20
Oil, gas and NGL (per Boe)...... $ 19.18 +70% 11.27 +20% 9.43
Absolute:
Oil............................. $ 116,427 +45% 80,298 +6% 75,493
Gas............................. $ 169,032 +48% 114,128 +27% 89,828
NGL............................. $ 18,078 +79% 10,075 +117% 4,644
----------- ------- -------
Oil, gas and NGL................ $ 303,537 +48% 204,501 +20% 169,965
=========== ======= =======
9
INTERNATIONAL
---------------------------------------------------------------------
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
----------- ------- --------- ------- -------
(ABSOLUTE AMOUNTS IN THOUSANDS)
PRODUCTION
Oil (MBbls)....................... 9,239 +6% 8,756 +23% 7,114
Gas (MMcf)........................ 8,775 (8)% 9,581 +1% 9,474
NGL (MBbls)....................... 16 +7% 15 (25)% 20
Oil, gas and NGL (MBoe)........... 10,717 +3% 10,368 +19% 8,713
REVENUES
Per Unit of Production:
Oil (per Bbl)................... $ 25.48 +50% 16.96 +47% 11.55
Gas (per Mcf)................... $ 1.32 +6% 1.24 (5)% 1.30
NGL (per Bbl)................... $ 21.19 +6% 20.00 +100% 10.00
Oil, gas and NGL (per Boe)...... $ 23.08 +49% 15.50 +43% 10.87
Absolute:
Oil............................. $ 235,435 +59% 148,501 +81% 82,200
Gas............................. $ 11,563 (3)% 11,900 (3)% 12,300
NGL............................. $ 339 +13% 300 +50% 200
----------- ------- ------
Oil, gas and NGL................ $ 247,337 +54% 160,701 +70% 94,700
=========== ======= ======
OIL REVENUES 2000 vs. 1999 Oil revenues increased $517.7 million in
2000. Oil revenues increased $326.8 million due to a $7.68 per barrel increase
in the average price of oil in 2000. An increase in 2000's production of 10.8
million barrels caused oil revenues to increase by $190.9 million. The
PennzEnergy merger accounted for 6.8 million barrels of the 10.8 million barrel
increase in production. The 2000 period included twelve months of production
from the properties acquired in the 1999 PennzEnergy merger, while the 1999
period only included production for 4 1/2 months following the August 17, 1999
merger closing. Additionally, drilling activity and less significant
acquisitions, offset in part by property dispositions and natural declines,
caused a 4.0 million barrel increase in production.
1999 vs. 1998 Oil revenues increased $251.0 million in 1999. Oil
revenues increased $176.9 million due to a $5.57 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 $74.1 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 added 1.1 million barrels of production
during the last eight months of 1999. This increase was partially offset by a
0.3 million barrel decline in 1999 production from Devon's other properties.
GAS REVENUES 2000 vs. 1999 Gas revenues increased $857.4 million in
2000. A 121.9 Bcf increase in production in 2000 added $251.7 million of gas
revenues compared to 1999. A $1.43 per Mcf increase in the average gas price in
2000 contributed $605.7 million of the increase in gas revenues. The PennzEnergy
merger accounted for 89.3 Bcf of the 121.9 Bcf increase in consolidated
production.
All of the 89.3 Bcf added by the PennzEnergy merger was attributable to
domestic properties. Production from Devon's other domestic properties increased
44.7 Bcf, due primarily to additional development and acquisitions, net of
natural declines and dispositions.
10
Canadian gas production decreased 11.3 Bcf, or 15%, in 2000. Natural
decline, increased royalty rates and dispositions of certain properties were the
primary reasons for the production decline. Whereas domestic royalty rates are
fixed percentages, the Canadian royalties are based on a sliding scale. As
prices increased in 2000, the Canadian government's royalty percentage also
increased, causing Devon's net production to decrease. Gross Canadian gas
production, before royalties, was 83.4 Bcf in 2000 compared to 92.1 Bcf in 1999.
1999 vs. 1998 Gas revenues increased $280.6 million in 1999. A 106.2
Bcf increase in production in 1999 added $186.1 million of gas revenues compared
to 1998. A $0.31 per Mcf increase in the average gas price in 1999 contributed
$94.5 million of the increase in gas revenues. The production increase was
primarily related to 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 eight 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.
NGL REVENUES 2000 vs. 1999 NGL revenues increased $86.5 million in
2000. An increase in 2000's average price of $7.57 per barrel caused NGL
revenues to increase $56.0 million. A production increase of 2.3 million barrels
in 2000 caused revenues to increase $30.5 million. The 1999 PennzEnergy merger
accounted for 2.5 million barrels of increased NGL production in 2000. This
increase was partially offset by a 0.2 million barrel reduction in 2000
production from Devon's other properties. This reduction was caused by property
dispositions and natural decline, offset in part by drilling activity and
property acquisitions.
1999 vs. 1998 NGL revenues increased $43.3 million in 1999. An increase
in 1999's average price of $5.21 per barrel caused NGL revenues to increase
$26.6 million. A production increase of 2.1 million barrels in 1999 caused
revenues to increase $16.7 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.
OTHER REVENUES 2000 vs. 1999 Other revenues increased $45.1 million, or
219% in 2000. Increases in third party gas processing income of $17.4 million
and interest income of $4.8 million were the primary reasons for the substantial
increase in other revenues. Additionally, the 2000 period included $18.4 million
of dividend income from the 7.1 million shares of Chevron Corporation common
stock acquired in the 1999 PennzEnergy merger. The 1999 period included $6.7
million of dividend income on these same shares.
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 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
1998 revenues more than offset increases of $9.8 million in 1999 from other
sources of revenues, including dividend income, 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.
11
EXPENSES The details of the changes in pre-tax expenses between 1998
and 2000 are shown in the table below.
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
------------ ------- ---------- ------- ---------
(ABSOLUTE AMOUNTS IN THOUSANDS)
Absolute:
Production and operating expenses:
Lease operating expenses.......................... $ 440,780 +48% 298,807 +32% 226,561
Transportation costs.............................. 53,309 +57% 33,925 +46% 23,186
Production taxes.................................. 103,244 +131% 44,740 +80% 24,871
Depreciation, depletion and amortization of
oil and gas properties.......................... 662,890 +70% 390,117 +69% 230,419
Amortization of goodwill............................ 41,332 +157% 16,111 N/M --
---------- ---------- ---------
Subtotal........................................ 1,301,555 +66% 783,700 +55% 505,037
Depreciation and amortization of non-oil and
gas properties.................................... 30,450 +87% 16,258 +28% 12,725
General and administrative expenses................. 93,008 +15% 80,645 +77% 45,454
Expenses related to mergers......................... 60,373 +259% 16,800 +28% 13,149
Interest expense.................................... 154,329 +41% 109,613 +152% 43,532
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt 2,408 N/M (13,154) N/M 16,104
Distributions on preferred securities of
subsidiary trust.................................. -- (100)% 6,884 (29)% 9,717
Reduction of carrying value of oil and gas
properties........................................ -- (100)% 476,100 +13% 422,500
---------- ---------- ---------
Total........................................... $1,642,123 +11% 1,476,846 +38% 1,068,218
========== ========== =========
Per Boe:
Production and operating expenses:
Lease operating expenses.......................... $ 3.65 +7% 3.41 (7)% 3.67
Transportation costs.............................. 0.44 +13% 0.39 +3% 0.38
Production taxes.................................. 0.85 +67% 0.51 +28% 0.40
Depreciation, depletion and amortization of
oil and gas properties.......................... 5.48 +23% 4.46 +19% 3.74
Amortization of goodwill............................ 0.34 +89% 0.18 N/M --
---------- ---------- ---------
Subtotal........................................ 10.76 +20% 8.95 +9% 8.19
Depreciation and amortization of non-oil and
gas properties (1)................................ 0.25 +32% 0.19 (10)% 0.21
General and administrative expenses (1)............. 0.77 (16)% 0.92 +24% 0.74
Expenses related to prior mergers (1)............... 0.50 +163% 0.19 (10)% 0.21
Interest expense (1)................................ 1.27 +2% 1.25 +79% 0.70
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt (1) 0.02 N/M (0.15) N/M 0.26
Distributions on preferred securities of
subsidiary trust (1).............................. -- (100)% 0.08 (50)% 0.16
Reduction of carrying value of oil and gas
properties (1).................................... -- (100)% 5.44 (21)% 6.85
---------- ---------- ---------
Total............................................ $ 13.57 (20)% 16.87 (3)% 17.32
========== ========== =========
----------
(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.
N/M - Not meaningful.
12
PRODUCTION AND OPERATING EXPENSES The details of the changes in
production and operating expenses between 1998 and 2000 are shown in the table
below.
TOTAL
----------------------------------------------------------
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
--------- ------- -------- ------- --------
(ABSOLUTE AMOUNTS IN THOUSANDS)
Absolute:
Recurring lease operating expenses........... $ 422,853 +45% 291,037 +33% 219,316
Well workover expenses....................... 17,927 +131% 7,770 +7% 7,245
Transportation costs......................... 53,309 +57% 33,925 +46% 23,186
Production taxes............................. 103,244 +131% 44,740 +80% 24,871
---------- --------- --------
Total production and operating expenses $ 597,333 +58% 377,472 +37% 274,618
========== ========= ========
Per Boe:
Recurring lease operating expenses........... $ 3.50 +5% 3.32 (7)% 3.56
Well workover expenses....................... 0.15 +67% 0.09 (18)% 0.11
Transportation costs......................... 0.44 +13% 0.39 +3% 0.38
Production taxes............................. 0.85 +67% 0.51 +28% 0.40
---------- --------- --------
Total production and operating expenses... $ 4.94 +15% 4.31 (3)% 4.45
========== ========= ========
2000 vs. 1999 Recurring lease operating expenses increased $131.8
million, or 45%, in 2000. The 1999 PennzEnergy merger accounted for $92.4
million of the increase in expenses. Additionally, $11.0 million of costs were
added by the August 1999 and January 2000 acquisitions of certain properties and
$7.7 million of costs were added by the Snyder merger. Other than the added
costs from these acquisitions, Devon's recurring costs increased $20.7 million
in 2000. This increase was primarily caused by increased production and higher
ad valorem taxes and fuel costs.
Transportation costs represent those costs paid directly to third-party
providers to transport oil and gas production sold downstream from the wellhead.
Transportation costs increased $19.4 million, or 57% in 2000 primarily due to
increased production.
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 143% increase in domestic oil, gas
and NGL revenues was the primary cause of a 136% 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 oil and 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.
1999 vs. 1998 Recurring lease operating expenses increased $71.7
million, or 33%, in 1999. The PennzEnergy properties added $57.3 million of
expenses in the last 4 1/2 months of the year, and the Snyder properties added
$17.7 million of expenses for the last eight months of the year. Other than the
added costs from the PennzEnergy and Snyder properties, recurring expenses on
Devon's other properties dropped $3.3 million in 1999. Efficiencies achieved in
certain of Devon's oil producing properties contributed a substantial portion of
this cost reduction.
13
Transportation costs increased $10.7 million, or 46% in 1999 primarily
due to increased production.
As previously stated, most of the U.S. production taxes are based on a
fixed percentage of revenues. Therefore, the 114% increase in domestic oil, gas
and NGL revenues was the primary cause of a 88% increase 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.
2000 vs. 1999 Oil and gas property related DD&A increased $272.8
million, or 70%, in 2000. Oil and gas property related DD&A increased $148.9
million due to the 38% increase in oil, gas and NGL production in 2000. Oil and
gas property related DD&A increased $123.9 million due to an increase in the
consolidated DD&A rate. The consolidated DD&A rate increased from $4.46 per Boe
in 1999 to $5.48 per Boe in 2000.
Non-oil and gas property DD&A increased $14.2 million in 2000 compared
to 1999. 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 2000's expense.
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 increased $96.7
million due to the 42% increase in oil, gas and NGL 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.
AMORTIZATION OF GOODWILL In connection with the PennzEnergy merger,
Devon recorded $346.9 million of goodwill. The goodwill was allocated $299.5
million to domestic operations and $47.4 million to international operations.
The goodwill is being amortized using the units-of-production method.
Substantially all of the $41.3 million and $16.1 million of amortization
recognized in 2000 and 1999, respectively, was related to the domestic balance.
14
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 the following table for a summary of G&A expenses by component.
TOTAL
-----------------------------------------------------
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
---------- ------- -------- ------- --------
(IN THOUSANDS)
Gross G&A............................ $ 205,693 +37% 150,441 +57% 95,589
Capitalized G&A...................... (61,764) +114% (28,878) +95% (14,812)
Reimbursed G&A....................... (50,921) +24% (40,918) +16% (35,323)
--------- ------- -------
Net G&A.......................... $ 93,008 +15% 80,645 +77% 45,454
========= ======= =======
2000 vs. 1999 Net G&A increased $12.4 million in 2000. Gross G&A
increased $55.3 million in 2000 compared to 1999. The increase in gross expenses
was primarily related to additional costs incurred as a result of the 1999
PennzEnergy and Snyder mergers. G&A was reduced $32.9 million in 2000 due to an
increase in the amount capitalized as part of oil and gas properties. G&A was
also reduced $10.0 million in 2000, by an increase in the amount of
reimbursements on operated properties in the 2000 period. The increase in
capitalized and reimbursed G&A was primarily related to the 1999 PennzEnergy and
Snyder mergers.
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.
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.
The increase, in absolute terms, in capitalized general and
administrative expenses from 1999 to 2000 was primarily a result of the 1999
PennzEnergy and 2000 Snyder mergers. Only 4 1/2 and 7 months of expenses related
to the PennzEnergy and Snyder mergers, respectively, were included in 1999.
The increase, on a percentage basis, in capitalized general and
administrative expenses from 1999 to 2000 was primarily related to an increase
in acquisition, exploration and development activities from 1999 to 2000. In
1999, Santa Fe Snyder experienced capital constraints as a result of lower
commodity prices. This led to a reduction in acquisition, exploration and
development activities, especially as it related to its international assets.
(The
15
capital constraints were also one of the considerations in Santa Fe's decision
to merge with Devon in 2000.) In 2000, with improving commodity prices and after
the announcement of the merger in May 2000, more money was being spent on
acquisition, exploration and development activities, overall, but especially on
the international assets. This is further evidenced by the increase in capital
expenditures from 1999 to 2000. Total capital expenditures were $883.4 million
in 1999 compared to $1,280.1 million in 2000. International capital expenditures
were $104.9 million in 1999 compared to $184.4 million in 2000. These same
considerations took place in the U.S. and Canada also, though the effects were
not as significant. Overall, the rising commodity prices in 2000 allowed Devon,
and Santa Fe Snyder prior to its merger with Devon, to focus more resources on
acquisition, exploration and development activities as compared to 1999. This
increase in acquisition, exploration and development activities meant that a
larger percentage of general and administrative costs specifically related to
such activities were subject to capitalization.
EXPENSES RELATED TO MERGERS Approximately $60.4 million of expenses
were incurred in 2000 in connection with the Santa Fe Snyder merger. These
expenses consisted primarily of severance and other benefit costs, investment
banking fees, other professional expenses, costs associated with duplicate
facilities and various transaction related costs. 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.
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.
INTEREST EXPENSE 2000 vs. 1999 Interest expense increased $44.7
million, or 41%, in 2000. An increase in the average debt balance outstanding
from $1.5 billion in 1999 to $2.3 billion in 2000 caused interest expense to
increase by $53.7 million. The increase in average debt outstanding in 2000 was
attributable to the long-term debt assumed in the Snyder and PennzEnergy mergers
on May 5, 1999 and August 17, 1999, respectively. The average interest rate on
outstanding debt decreased from 7.0% in 1999 to 6.7% in 2000. This rate decrease
caused interest expense to decrease $4.7 million in 2000. 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 $4.3 million lower in 2000 compared to 1999.
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
increase in average debt outstanding in 1999 was attributable to the long-term
debt assumed in the Snyder and PennzEnergy mergers on
16
May 5, 1999 and August 17, 1999, respectively. 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.
DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATE ON
SUBSIDIARY'S LONG-TERM DEBT 2000 vs. 1999 Until mid-January 2000, Devon's
Canadian subsidiary Northstar Energy Corporation 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 were required to be included in
determining net earnings for the period in which the exchange rate changed. 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. The Canadian-to-U.S. dollar exchange rate dropped slightly in
January prior to the debt retirement. As a result, $2.4 million of expense was
recognized in 2000.
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.
DISTRIBUTIONS ON PREFERRED SECURITIES OF SUBSIDIARY TRUST As discussed
in Note 9 to the consolidated financial statements, 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.
2000 vs. 1999 There were no TCP Securities distributions in 2000
compared to $6.9 million in 1999. Substantially all of the TCP Securities were
exchanged for shares of Devon common stock on November 30, 1999.
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.
17
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.
Devon did not reduce the carrying value of its oil and gas properties
in 2000. During 1999 and 1998, Devon reduced the carrying value of its oil and
gas properties by $476.1 million and $422.5 million, respectively, due to the
full-cost ceiling limitations. The after-tax effect of these reductions in 1999
and 1998 were $309.7 million and $280.8 million, respectively.
INCOME TAXES 2000 vs. 1999 Devon's 2000 financial tax expense rate was
36% of income before income tax expense. This rate was higher 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,
offset in part by the recognition of a benefit from the disposition of Devon's
assets in Venezuela. The 1999 financial tax benefit rate was 25%. 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.
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%.
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 $1.3 billion was spent in 2000 for
capital expenditures, of which $1.2 billion was related to the acquisition,
drilling or development of oil and gas properties. These amounts compare to 1999
total expenditures of $883.4 million ($784.9 million of which was related to oil
and gas properties) and 1998 total expenditures of $712.8 million ($704.6
million of which was related to oil and gas properties.)
OTHER CASH USES Devon's common stock dividends were $22.2 million,
$12.7 million and $7.3 million in 2000, 1999 and 1998, respectively. Devon also
paid $9.7 million of preferred stock dividends in 2000 and $3.7 million in the
last 4 1/2 months of 1999 following the PennzEnergy merger.
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 $1.6 billion,
$532.3 million and $334.5 million in 2000, 1999 and 1998,
18
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 2000 and 1999, debt repayments exceeded borrowings by $371.6
million and $144.7 million, respectively. During 1998, long-term debt borrowings
exceeded repayments by $264.2 million.
Prior to the August 2000 merger, Devon and Santa Fe Snyder each had
their own unsecured credit facilities. 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. As of December 31, 2000, Devon had no
borrowings under its U.S. Facility.
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. As of December 31, 2000, Devon had $146.7 million
borrowed under its Canadian Facility at a weighted average interest rate of
6.1%.
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
19
elect to borrow at the prime rate. The Credit Facilities provide for an annual
facility fee of $0.9 million that is payable quarterly.
On August 29, 2000, Devon entered into a commercial paper program.
Total borrowings under the U.S. credit facility and the commercial paper program
may not exceed $725 million. The commercial paper borrowings may have terms of
up to 365 days and bear interest at rates agreed to at the time of the
borrowing. The interest rate will be based on a standard index such as the
Federal Funds Rate, London Interbank Offered Rate (LIBOR), or the money market
rate as found on the commercial paper market. As of December 31, 2000, Devon had
no borrowings under its commercial paper program.
In June 2000, Devon privately sold zero coupon convertible senior
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 of the 760,000
debentures is convertible into 5.7593 shares of Devon common stock. Devon may
call the debentures at any time after five years, and a debenture holder has the
right to require Devon to repurchase the debentures after five, 10 and 15 years,
at the issue price plus accrued original issue discount and interest. The
proceeds to Devon 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.
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.
2001 ESTIMATES
The forward-looking statements provided in this discussion are based on
management's examination of historical operating trends, the information which
was used to prepare the December 31, 2000 reserve reports of independent
petroleum engineers and other data in Devon's possession or available from third
parties. Devon cautions that its future oil, natural gas and NGL production,
revenues and expenses are subject to all of the risks and uncertainties normally
incident to the exploration for and development and production and sale of oil
and gas. These risks include, but are not limited to, price volatility,
inflation, the lack of availability of goods and services, environmental risks,
drilling risks, regulatory changes, the uncertainty inherent in estimating
future oil and gas production or reserves, and other risks as outlined below.
Also, the financial results of Devon's foreign operations are subject to
currency exchange rate risks. Additional risks are discussed below in the
context of line items most affected by such risks.
SPECIFIC ASSUMPTIONS AND RISKS RELATED TO PRICE AND PRODUCTION
ESTIMATES Prices for oil, natural gas and NGL are determined primarily by
prevailing market conditions. Market conditions for these products are
influenced by regional and world-wide economic growth, weather and other
substantially variable factors. These factors are beyond Devon's control and are
difficult to predict. In addition to volatility in general, Devon's oil, gas and
NGL prices may
20
vary considerably due to differences between regional markets, transportation
availability and demand for different grades of oil, gas and NGL. Over 97% of
Devon's revenues are attributable to sales of these three commodities.
Consequently, Devon's financial results and resources are highly influenced by
this price volatility.
Estimates for Devon's future production of oil, natural gas and NGL are
based on the assumption that market demand and prices for oil and gas will
continue at levels that allow for profitable production of these products. There
can be no assurance of such stability. Also, Devon's International production of
oil, natural gas and NGL is governed by payout agreements with the governments
of the countries in which Devon operates. If the payout under these agreements
is attained earlier than projected, Devon's net production and proved reserves
in such areas could be reduced.
The production, transportation and marketing of oil, natural gas and
NGL are complex processes which are subject to disruption due to transportation
and processing availability, mechanical failure, human error, meteorological
events, including, but not limited to, hurricanes, and numerous other factors.
The following forward-looking statements were prepared assuming demand,
curtailment, producibility and general market conditions for Devon's oil,
natural gas and NGL during 2001 will be substantially similar to those of 2000,
unless otherwise noted. Given the general limitations expressed herein, Devon's
forward-looking statements for 2001 are set forth below. Unless otherwise noted,
all of the following dollar amounts are expressed in U.S. dollars. Those amounts
related to Canadian operations have been converted to U.S. dollars using an
exchange rate of $0.6695 U.S. dollar to $1.00 Canadian dollar. The actual 2001
exchange rate may vary materially from this estimated rate. Such variations
could have a material effect on the following Canadian estimates.
GEOGRAPHIC REPORTING AREAS FOR 2001 The following estimates of
production, average price differentials and capital expenditures are provided
separately for each of Devon's geographic divisions. These divisions are as
follows:
o the Gulf Division, which operates oil and gas properties located primarily
in the onshore South Texas and South Louisiana areas and offshore in the
Gulf of Mexico;
o the Rocky Mountain Division, which operates oil and gas properties located
in the Rocky Mountains area of the United States stretching from the
Canadian border south into northern New Mexico;
o the Permian/Mid-Continent Division, which operates all properties located
in the United States other than those operated by the Gulf Division and the
Rocky Mountain Division;
o Canada; and
o International Division, which encompasses all oil and gas properties that
lie outside of the United States and Canada.
21
YEAR 2001 POTENTIAL OPERATING ITEMS
OIL, GAS AND NGL PRODUCTION Set forth in the following paragraphs are
individual estimates of Devon's oil, gas and NGL production in 2001. On a
combined basis, Devon estimates its 2001 oil, gas and NGL production will total
between 120.4 million and 128.0 million barrels of oil equivalent. Devon's
estimates of 2001 production do not include certain oil, gas and NGL production
from various properties that were sold during 2000. These sold properties
produced approximately 2.9 million barrels of oil equivalent in 2000 that will
not be produced by Devon in 2001.
OIL PRODUCTION Devon expects its oil production in 2001 to total
between 40.3 million barrels and 42.8 million barrels. The expected ranges of
production by division are as follows:
Expected Range of
Production (MMBbls)
-------------------
Permian/Mid-Continent 12.2 to 12.9
Gulf 10.1 to 10.8
Rocky Mountain 3.0 to 3.2
Canadian 5.3 to 5.6
International 9.7 to 10.3
OIL PRICES - FIXED Devon has fixed the price it will receive in 2001 on
a portion of its oil production through certain forward oil sales. Devon has
executed forward oil sales attributable to the Permian/Mid-Continent Division
for 3.7 million barrels at an average price of $16.84 per barrel. These
fixed-price volumes represent 9% of Devon's expected consolidated oil production
in 2001. Santa Fe Snyder Corporation entered into these forward oil sales
agreements in late 1999 and early 2000, and used the proceeds to acquire
interests in producing properties in the Gulf of Mexico.
OIL PRICES - FLOATING For the oil production for which prices have not
been fixed, Devon's 2001 average prices for each of its divisions are expected
to differ from the New York Mercantile Exchange price ("NYMEX") as set forth in
the following table. The NYMEX price is the monthly average of settled prices on
each trading day for West Texas Intermediate Crude oil delivered at Cushing,
Oklahoma.
Expected Range of Oil Prices
Greater Than (Less Than) NYMEX
------------------------------
Permian/Mid-Continent ($3.10) to ($2.10)
Gulf ($2.90) to ($1.90)
Rocky Mountain ($2.50) to ($1.50)
Canadian ($5.50) to ($4.50)
International ($3.65) to ($2.65)
The above range of expected Canadian differentials compared to NYMEX
includes an estimated $0.11 per barrel decrease resulting from foreign currency
hedges. These hedges, in which Devon will sell $10 million in 2001 at an average
Canadian-to-U.S. exchange rate of $0.7102 and buy the same amount of dollars at
the floating exchange rate, offset a portion of the
22
exposure to currency fluctuations on those Canadian oil sales that are based on
U.S. prices. The $0.11 per barrel decrease is based on the assumption that the
average Canadian-to-U.S. conversion rate for the year 2001 is $0.6695.
GAS PRODUCTION Devon expects its 2001 gas production to total between
439 Bcf and 469 Bcf. The expected ranges of production by division are as
follows:
Expected Range of
Production (Bcf)
----------------
Permian/Mid-Continent 114 to 121
Gulf 144 to 153
Rocky Mountain 115 to 123
Canadian 58 to 62
International 8 to 10
GAS PRICES - FIXED Through various price swaps and fixed-price physical
delivery contracts, Devon has fixed the price it will receive in 2001 on a
portion of its natural gas production. The following tables include information
on this fixed-price production by division. Where necessary, the prices have
been adjusted for certain transportation costs that are netted against the price
recorded by Devon, and the price has also been adjusted for the Btu content of
the gas production that has been hedged.
FIRST HALF OF 2001 SECOND HALF OF 2001
------------------------------- ----------------------------
DIVISION Mcf/DAY PRICE/Mcf Mcf/DAY PRICE/Mcf
-------- ------- --------- ------- ---------
Rocky Mountain 20,661 $ 1.90 57,955 $ 3.68
Gulf -- $ -- 40,000 $ 5.45
Canada 60,011 $ 1.53 56,888 $ 1.52
Additionally, Devon has entered into a basis swap on 7.3 Bcf of 2001
gas production. Under the terms of the basis swap, the counterparty pays Devon
the average NYMEX price for the last three trading days of each month, less
$0.30 per Mcf. In return, Devon pays the counterparty the Colorado Interstate
Gas Co. ("CIG") index price published by "Inside F.E.R.C.'s Gas Market Report"
("Inside FERC"). The effect of this swap is included in Rocky Mountain Division
gas revenues. This basis swap does not qualify as a hedge under the provisions
of SFAS No. 133. Accordingly, fluctuations in the fair value of this basis swap
will be recorded in earnings beginning in the first quarter of 2001.
GAS PRICES - FLOATING For the natural gas production for which prices
have not been fixed, Devon's 2001 average prices for each of its divisions are
expected to differ from NYMEX as set forth in the following table. NYMEX is
determined to be the first-of-month South Louisiana Henry Hub price index as
published monthly in "Inside FERC."
23
Expected Range of Gas Prices
Greater Than (Less Than) NYMEX
------------------------------
Permian/Mid-Continent ($0.40) to $0.10
Gulf ($0.15) to $0.35
Rocky Mountain ($0.90) to ($0.40)
Canadian ($0.85) to ($0.35)
International ($2.60) to ($2.10)
Devon has also entered into a costless price collar that sets a floor
and ceiling price for 20,000 MMBtu/day of Rocky Mountain Division gas production
during the second half of 2001. The collar has a floor and ceiling price per
MMBtu of $4.10 and $8.00, respectively. The floor and ceiling prices are based
on the first-of-the-month CIG price index as published monthly by Inside FERC.
If the CIG index is outside of the ranges set by the floor and ceiling prices,
Devon and the counterparty to the collar will settle the difference. Any such
settlements will either increase or decrease Devon's gas revenues for the
period. Because Devon's gas volumes are often sold at prices that differ from
related regional indices, and due to differing Btu content of gas production,
the floor and ceiling prices of the collar do not reflect actual limits of
Devon's realized prices for the production volumes related to the collar.
NGL PRODUCTION Devon expects its 2001 production of NGL to total
between 6.6 million barrels and 7.3 million barrels. The expected ranges of
production by division are as follows:
Expected Range of
Production (MMBbls)
-------------------
Permian/Mid-Continent 4.3 to 4.6
Gulf 1.0 to 1.1
Rocky Mountain 0.6 to 0.7
Canadian 0.5 to 0.6
International 0.2 to 0.3
OTHER REVENUES Devon's other revenues in 2001 are expected to be
between $53 million and $59 million. This estimated range does not include the
gain or loss that could be recognized from changes in the fair values of Devon's
derivatives that are not hedges. Substantially all of Devon's derivatives are
hedges, but the gas price basis swap previously discussed and the option
embedded in the debentures that are exchangeable into shares of Chevron
Corporation common stock are not hedges. Accordingly, the changes in the fair
value of these derivatives will be recognized in Devon's operating results in
2001.
PRODUCTION AND OPERATING EXPENSES Devon's production and operating
expenses include lease operating expenses, transportation costs and production
taxes. These expenses vary in response to several factors. Among the most
significant of these factors are additions to or deletions from Devon's property
base, changes in production tax rates, changes in the general price level of
services and materials that are used in the operation of the properties and the
amount of repair and workover activity required. Oil, natural gas and NGL prices
also have an effect on lease operating expense and impact the economic
feasibility of planned workover projects.
24
These factors, coupled with uncertainty of future oil, natural gas and
NGL prices, increase the uncertainty inherent in estimating future production
and operating costs. Given these uncertainties, Devon estimates that year 2001
lease operating expense will be between $463 million and $492 million,
transportation costs will be between $62 million and $66 million and production
taxes will be between 4% and 5% of consolidated oil, natural gas and NGL
revenues.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") The 2001 oil and gas
property DD&A rate will depend on various factors. Most notable among such
factors are the amount of proved reserves that will be added from drilling or
acquisition efforts in 2001 compared to the costs incurred for such efforts, and
the revisions to Devon's year-end 2000 reserve estimates that, based on prior
experience, are likely to be made during 2001.
In addition to oil and gas property related DD&A, Devon expects its
2001 DD&A expense related to non-oil and gas property fixed assets to total
between $30 million and $32 million. Based on this range and the production
estimates discussed earlier, Devon expects its 2001 consolidated DD&A rate to
total between $6.15 per Boe and $6.45 per Boe.
Devon also expects to record goodwill amortization in 2001 of between
$33 million and $35 million. The goodwill was recorded in connection with the
1999 merger with PennzEnergy.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon's G&A includes the costs of
many different goods and services used in support of its business. These goods
and services are subject to general price level increases or decreases. In
addition, Devon's G&A varies with its level of activity and the related staffing
needs as well as with the amount of professional services required during any
given period. Should Devon's needs or the prices of the required goods and
services differ significantly from current expectations, actual G&A could vary
materially from the estimate. Given these limitations, consolidated G&A in 2001
is expected to be between $89 million and $98 million.
INTEREST EXPENSE Future interest rates and oil, natural gas and NGL
prices have a significant effect on Devon's interest expense. Approximately $1.9
billion of Devon's December 31, 2000, long-term debt balance of $2.0 billion
bears interest at fixed rates. Such fixed rates remove the uncertainty of future
interest rates from some, but not all, of Devon's long-term debt. Also, Devon
can only marginally influence the prices it will receive in 2001 from sales of
oil, natural gas and NGL and the resulting cash flow. These factors increase the
margin of error inherent in estimating future interest expense. Other factors
which affect interest expense, such as the amount and timing of capital
expenditures, are within Devon's control. Given the uncertainty of future
interest rates and commodity prices, and assuming that the fixed-rate debt
remains in place throughout the year, Devon estimates that the consolidated
interest expense in 2001 will be between $143 million and $146 million. Included
in this estimate is $12 million of discount accretion on the debentures that are
exchangeable into shares of Chevron Corporation common stock. The discount
accretion is the result of the adoption of SFAS 133 effective January 1 2001.
25
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES As of December
31, 2000, Devon does not expect to record a reduction in 2001 of its carrying
value of oil and natural gas properties under the full-cost accounting ceiling
test. At this time the ceiling for each full-cost pool exceeds Devon's carrying
value of oil and natural gas properties, less deferred income taxes. However,
such excess could be eliminated by declines in oil and/or natural gas prices
between now and the end of any quarter during 2001 or in subsequent periods.
INCOME TAXES Devon expects its consolidated financial income tax rate
in 2001 to be between 35% and 45%. The current income tax rate is expected to be
between 20% and 25%. The deferred income tax rate is expected to be between 15%
and 20%. There are certain items that will have a fixed impact on 2001's income
tax expense regardless of the level of pre-tax earnings that are produced. These
items include Section 29 tax credits in the U.S., which reduce income taxes
based on production levels of certain properties and are not necessarily
affected by pre-tax financial earnings. The amount of Section 29 tax credits
expected to be generated to offset financial income tax expense in 2001 is
approximately $20 million. Also, Devon's Canadian subsidiaries are subject to
Canada's "large corporation tax" of approximately $3 million which is based on
total capitalization levels, not pre-tax earnings. The financial income tax in
2000 will also be increased by approximately $14 million due to the financial
amortization of certain costs, such as goodwill amortization, that are not
deductible for income tax purposes. Significant changes in estimated production
levels of oil, gas and NGL, the prices of such products, or any of the various
expense items could materially alter the effect of the aforementioned items on
2001's financial income tax rates.
YEAR 2001 POTENTIAL CAPITAL SOURCES, USES AND LIQUIDITY
CAPITAL EXPENDITURES Though Devon has completed several major property
acquisitions in recent years, these transactions are opportunity driven. Thus,
Devon does not "budget," nor can it reasonably predict, the timing or size of
such possible acquisitions, if any.
Devon's capital expenditures budget is based on an expected range of
future oil, natural gas and NGL prices as well as the expected costs of the
capital additions. Should Devon's price expectations for its future production
change significantly, some projects may be accelerated or deferred and,
consequently, may increase or decrease total 2001 capital expenditures. In
addition, if the actual costs of the budgeted items vary significantly from the
anticipated amounts, actual capital expenditures could vary materially from
Devon's estimates.
Given the limitations discussed, the company expects its 2001 capital
expenditures for drilling and development efforts plus related facilities to
total between $1.05 billion and $1.15 billion. These amounts include between
$160 million and $180 million for drilling and facilities costs related to
reserves expected to be classified as proved as of year-end 2000. In addition,
these amounts include between $520 million and $560 million for other low
risk/reward projects and between $370 million and $410 million for new, higher
risk/reward projects. The following table shows expected drilling and facilities
expenditures by major operating division.
26
DRILLING AND PRODUCTION FACILITIES EXPENDITURES (MILLIONS)
---------------------------------------------------------------------------
PERMIAN/
ROCKY MID-
MOUNTAIN CONTINENT GULF OTHER
DIVISION DIVISION DIVISION CANADA INTERNATIONAL
--------- --------- --------- --------- -------------
Related to Proved Reserves $45-$55 $70-$80 $0-$10 $10-$20 $20-$30
Lower Risk/Reward Projects $45-$55 $90-$100 $185-$215 $40-$50 $140-$170
Higher Risk/Reward Projects $20-$30 $40-$50 $110-$130 $105-$125 $80-$100
--------- --------- --------- --------- ---------
Total $110-$140 $200-$230 $295-$355 $155-$195 $240-$300
========= ========= ========= ========= =========
In addition to the above expenditures for drilling and development,
Devon is participating through a joint venture in the construction of gas
transportation and processing systems in the Powder River Basin of Wyoming.
Devon expects to spend from $15 million to $20 million as its share of the
project in 2001. Devon also expects to capitalize between $70 million and $80
million of G&A expenses in accordance with the full-cost method of accounting.
Devon also expects to pay between $15 million and $20 million for plugging and
abandonment charges in 2001. Finally, Devon expects to spend between $15 million
and $20 million for non-oil and gas property fixed assets.
OTHER CASH USES Devon's management expects the policy of paying a
quarterly common stock dividend to continue. With the current $0.05 per share
quarterly dividend rate and 129 million shares of common stock outstanding, 2001
dividends are expected to approximate $26 million. Also, Devon has $150 million
of 6.49% cumulative preferred stock upon which it will pay $9.7 million of
dividends in 2001.
CAPITAL RESOURCES AND LIQUIDITY Devon's estimated 2001 cash uses,
including its drilling and development activities, are expected to be funded
primarily through a combination of working capital and operating cash flow, with
the remainder, if any, funded with borrowings from Devon's Credit Facilities.
The amount of operating cash flow to be generated during 2001 is uncertain due
to the factors affecting revenues and expenses as previously cited. However,
Devon expects its combined capital resources to be more than adequate to fund
its anticipated capital expenditures and other cash uses for 2001. As of
December 31, 2000, Devon had $853 million available under its $1 billion Credit
Facilities. If significant acquisitions or other unplanned capital requirements
arise during the year, Devon could utilize its existing Credit Facilities and/or
seek to establish and utilize other sources of financing.
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
27
derivative (that is gains and losses) depends on the intended use of the
derivative and whether it qualifies as a hedge. Devon adopted the provisions of
SFAS 133, as amended, in the first quarter of the year ending December 31, 2001.
In accordance with the transition provisions of SFAS 133, Devon recorded a
net-of-tax cumulative-effect-type adjustment of $36.6 million in accumulated
other comprehensive loss to recognize at fair value all derivatives that are
designated as cash-flow hedging financial instruments. Additionally, Devon
recorded a net-of-tax cumulative-effect-type adjustment to net earnings for a
$49.5 million gain related to the fair value of financial instruments that do
not qualify as hedges. This gain included $46.2 million related to the option
embedded in Devon's debentures that are exchangeable into shares of Chevron
Corporation common stock.
28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED
FINANCIAL STATEMENT SCHEDULES
Page
----
Independent Auditors' Reports............................................................................. 30
Consolidated Financial Statements:
Consolidated Balance Sheets
December 31, 2000, 1999, and 1998................................................................... 33
Consolidated Statements of Operations
Years Ended December 31, 2000, 1999, and 1998....................................................... 34
Consolidated Statements of Stockholders' Equity
Years Ended December 31, 2000, 1999, and 1998....................................................... 35
Consolidated Statements of Cash Flows
Years Ended December 31, 2000, 1999, and 1998....................................................... 36
Notes to Consolidated Financial Statements
December 31, 2000, 1999, and 1998................................................................... 37
All financial statement schedules are omitted as they are inapplicable or the
required information has been included in the consolidated financial statements
or notes thereto.
29
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Devon Energy Corporation:
We have audited the accompanying consolidated balance sheets of Devon Energy
Corporation and subsidiaries (the Company) as of December 31, 2000, 1999 and
1998, and the related consolidated statements of operations, stockholders'
equity, and cash flows for each of the years then ended. These consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits. We did not audit the 1999 and 1998 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% and 43% in 1999 and 1998, respectively, of the
related consolidated totals. We did not audit the 1998 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% in 1998 of the
related consolidated totals. The 1999 and 1998 financial statements of Santa Fe
Snyder Corporation and the 1998 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 and 1998, and Northstar Energy Corporation in 1998,
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.
In our opinion, based on our audits and the reports of the other auditors, the
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, 2000, 1999 and 1998, and the results of their
operations and their cash flows for each of the years then ended, in conformity
with accounting principles generally accepted in the United States of America.
KPMG LLP
Oklahoma City, Oklahoma
January 30, 2001
30
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
Santa Fe Snyder Corporation:
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations, comprehensive income, shareholders'
equity and of cash flows present fairly, in all material respects, the financial
position of Santa Fe Snyder Corporation and its subsidiaries at December 31,
1999 and 1998, and the results of their operations and their cash flows for each
of the two years in the period ended December 31, 1999 (not separately presented
herein) in conformity with accounting principles generally accepted in the
United States of America. These 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 of these
statements in accordance with auditing standards generally accepted in the
United States of America, which 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, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
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 second paragraph
above which are as of October 30, 2000
31
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 the year 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 audit.
We conducted our audit 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 at December 31, 1998,
and the results of its operations and the changes in its cash flow for the year
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
32
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31,
------------------------------------------------
2000 1999 1998
------------ ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents $ 228,050 173,167 31,254
Accounts receivable 598,248 316,005 137,058
Inventories 47,272 38,941 21,750
Deferred income taxes 8,979 4,886 605
Investments and other current assets 51,588 57,295 35,981
------------ ------------ ------------
Total current assets 934,137 590,294 226,648
------------ ------------ ------------
Property and equipment, at cost, based on the full
cost method of accounting for oil and gas properties
($315,260, $301,185 and $213,577 excluded from
amortization in 2000, 1999 and 1998, respectively) 9,709,352 8,592,010 4,854,211
Less accumulated depreciation, depletion and
amortization 4,799,816 4,168,590 3,230,683
------------ ------------ ------------
4,909,536 4,423,420 1,623,528
Investment in Chevron Corporation common stock,
at fair value 598,867 614,382 --
Deferred income taxes -- -- 54,381
Goodwill, net of amortization 289,489 322,800 --
Other assets 128,449 145,464 25,980
------------ ------------ ------------
Total assets $ 6,860,478 6,096,360 1,930,537
============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade 320,713 266,825 155,377
Revenues and royalties due to others 116,481 67,330 20,608
Income taxes payable 65,674 12,587 1,200
Accrued interest payable 23,191 28,370 5,588
Merger related expenses payable 52,421 35,704 7,882
Accrued expenses 50,507 56,528 29,201
------------ ------------ ------------
Total current liabilities 628,987 467,344 219,856
------------ ------------ ------------
Other liabilities 164,469 241,782 71,947
Debentures exchangeable into shares of Chevron
Corporation common stock 760,313 760,313 --
Other long-term debt 1,288,523 1,656,208 735,871
Deferred revenue 113,756 104,800 3,600
Deferred income taxes 626,826 344,593 --
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 2000 and 1,500 1,500 --
1999 and none in 1998
Common stock of $.10 par value
Authorized 400,000,000 shares; issued
128,638,000 in 2000, 126,323,000 in 1999 and
70,909,000 in 1998 12,864 12,632 7,090
Additional paid-in capital 3,563,994 3,491,828 1,523,944
Retained earnings (accumulated deficit) (214,708) (908,598) (737,009)
Accumulated other comprehensive loss (85,397) (65,242) (35,962)
Unamortized restricted stock awards (649) -- (1,500)
Treasury stock, at cost: 330,000 shares in 1999 and
176,000 shares in 1998 -- (10,800) (6,800)
------------ ------------ ------------
Total stockholders' equity 3,277,604 2,521,320 749,763
------------ ------------ ------------
Commitments and contingencies (Notes 12 and 13)
Total liabilities and stockholders' equity $ 6,860,478 6,096,360 1,930,537
============ ============ ============
See accompanying notes to consolidated financial statements.
33
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
-----------------------------------------------
2000 1999 1998
------------ ------------ ------------
REVENUES
Oil sales $ 1,078,759 561,018 309,990
Gas sales 1,485,221 627,869 347,273
Natural gas liquids sales 154,465 67,985 24,715
Other 65,658 20,596 24,248
------------ ------------ ------------
Total revenues 2,784,103 1,277,468 706,226
------------ ------------ ------------
COSTS AND EXPENSES
Lease operating expenses 440,780 298,807 226,561
Transportation costs 53,309 33,925 23,186
Production taxes 103,244 44,740 24,871
Depreciation, depletion and amortization of property
and equipment 693,340 406,375 243,144
Amortization of goodwill 41,332 16,111 --
General and administrative expenses 93,008 80,645 45,454
Expenses related to mergers 60,373 16,800 13,149
Interest expense 154,329 109,613 43,532
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt 2,408 (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 1,642,123 1,476,846 1,068,218
------------ ------------ ------------
Earnings (loss) before income tax expense (benefit)
and extraordinary item 1,141,980 (199,378) (361,992)
INCOME TAX EXPENSE (BENEFIT)
Current 130,793 23,056 (3,713)
Deferred 280,845 (72,490) (122,394)
------------ ------------ ------------
Total income tax expense (benefit) 411,638 (49,434) (126,107)
------------ ------------ ------------
Earnings (loss) before extraordinary item 730,342 (149,944) (235,885)
Extraordinary loss -- (4,200) --
------------ ------------ ------------
Net earnings (loss) 730,342 (154,144) (235,885)
Preferred stock dividends 9,735 3,651 --
------------ ------------ ------------
Net earnings (loss) applicable to common shareholders $ 720,607 (157,795) (235,885)
============ ============ ============
Net earnings (loss) per average common share outstanding:
Before extraordinary loss:
Basic $ 5.66 (1.64) (3.32)
============ ============ ============
Diluted $ 5.50 (1.64) (3.32)
============ ============ ============
After extraordinary loss:
Basic $ 5.66 (1.68) (3.32)
============ ============ ============
Diluted $ 5.50 (1.68) (3.32)
============ ============ ============
Weighted average common shares outstanding:
Basic 127,421 93,653 70,948
============ ============ ============
Diluted 131,730 99,313 76,932
============ ============ ============
See accompanying notes to consolidated financial statements.
34
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
ACCUMU-
RETAINED LATED UNAMOR-
EARNINGS OTHER TIZED TOTAL
PREFER- ADDITIONAL (ACCUMU- COMPRE- RESTRICTED STOCK-
RED COMMON PAID-IN LATED HENSIVE STOCK TREASURY HOLDERS'
STOCK STOCK CAPITAL DEFICIT) LOSS AWARDS STOCK EQUITY
--------- ------ ---------- -------- ------- ---------- -------- ----------
Balance as of December 31, 1997 $ -- 7,077 1,521,128 (493,246) (27,113) (700) (600) 1,006,546
Comprehensive loss:
Net loss -- -- -- (235,885) -- -- -- (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 -- 13 2,816 (600) -- (2,600) 5,400 5,029
Stock repurchased -- -- -- -- -- -- (11,600) (11,600)
Dividends on common stock -- -- -- (7,278) -- -- -- (7,278)
Amortization of restricted stock awards -- -- -- -- -- 1,800 -- 1,800
--------- ------ ---------- -------- ------- ---------- -------- ----------
Balance as of December 31, 1998 -- 7,090 1,523,944 (737,009) (35,962) (1,500) (6,800) 749,763
Comprehensive loss:
Net loss -- -- -- (154,144) -- -- -- (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 1,500 5,542 1,966,930 (1,100) -- (100) 7,600 1,980,372
Stock repurchased -- -- -- -- -- -- (11,600) (11,600)
Tax benefit related to employee
stock options -- -- 954 -- -- -- -- 954
Dividends on common stock -- -- -- (12,694) -- -- -- (12,694)
Dividends on preferred stock -- -- -- (3,651) -- -- -- (3,651)
Amortization of restricted stock awards -- -- -- -- -- 1,600 -- 1,600
--------- ------ ---------- -------- ------- ---------- -------- ----------
Balance as of December 31, 1999 1,500 12,632 3,491,828 (908,598) (65,242) -- (10,800) 2,521,320
Comprehensive income:
Net income -- -- -- 730,342 -- -- -- 730,342
Other comprehensive loss, net of tax:
Foreign currency translation
adjustments -- -- -- -- (10,213) -- -- (10,213)
Minimum pension liability
adjustment -- -- -- -- 822 -- -- 822
Unrealized losses on marketable
securities -- -- -- -- (10,764) -- -- (10,764)
----------
Other comprehensive loss -- -- -- -- -- -- -- (20,155)
----------
Comprehensive income: 710,187
Stock issued -- 232 69,163 (4,497) -- -- 21,499 86,397
Stock repurchased -- -- -- -- -- (10,699) (10,699)
Tax benefit related to employee stock
options -- -- 3,003 -- -- -- -- 3,003
Dividends on common stock -- -- -- (22,220) -- -- -- (22,220)
Dividends on preferred stock -- -- -- (9,735) -- -- -- (9,735)
Grant of restricted stock awards -- -- -- -- -- (5,217) -- (5,217)
Forfeiture of restricted stock awards -- -- -- -- -- 129 -- 129
Amortization of restricted stock awards -- -- -- -- -- 4,439 -- 4,439
--------- ------ ---------- -------- ------- ---------- -------- ----------
Balance as of December 31, 2000 $ 1,500 12,864 3,563,994 (214,708) (85,397) (649) -- 3,277,604
========= ====== ========== ======== ======= ========== ======== ==========
See accompanying notes to consolidated financial statements.
35
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
------------------------------------------------
2000 1999 1998
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net earnings (loss) $ 730,342 (154,144) (235,885)
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization of property
and equipment 693,340 406,375 243,144
Amortization of goodwill 41,332 16,111 --
Accretion of interest on zero-coupon convertible
senior debentures 6,950 -- --
Amortization of (premiums) discounts on other
long-term debt, net (3,781) (728) 100
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt 2,408 (13,154) 16,104
Reduction of carrying value of oil and gas properties -- 476,100 422,500
(Gain) loss on sale of assets (683) 4,778 (264)
Deferred income tax expense (benefit) 280,845 (72,490) (122,394)
Other 3,849 2,100 4,801
Changes in assets and liabilities, net of effects of
acquisitions of businesses:
(Increase) decrease in:
Accounts receivable (283,787) (92,416) 30,760
Inventories (8,322) (8,514) (1,427)
Prepaid expenses 5,825 (4,418) (7,751)
Other assets 3,812 (36,673) 17,230
Increase (decrease) in:
Accounts payable 98,912 (22,495) (19,439)
Income taxes payable 60,548 (19,318) (10,426)
Accrued expenses 3,104 (38,387) 1,000
Deferred revenue 7,954 90,700 (100)
Long-term other liabilities (23,616) (1,099) (3,482)
------------ ------------ ------------
Net cash provided by operating activities 1,619,032 532,328 334,471
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of property and equipment 101,531 114,384 64,997
Proceeds from sale of investments 12,781 -- 42,584
Capital expenditures (1,280,132) (883,420) (712,812)
(Increase) decrease in other assets (7,581) 719 (2,029)
------------ ------------ ------------
Net cash used in investing activities (1,173,401) (768,317) (607,260)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings of long-term debt, net of issuance
costs 2,580,086 1,944,417 1,506,220
Principal payments on long-term debt (2,951,711) (2,089,109) (1,242,013)
Issuance of common stock, net of issuance costs 51,550 530,232 4,429
Retirement of preferred securities of subsidiary trust -- (50) --
Repurchase of common stock (10,699) (11,600) (11,600)
Issuance of treasury stock 24,937 6,200 --
Dividends paid on common stock (22,220) (12,694) (7,278)
Dividends paid on preferred stock (9,735) (3,651) --
(Decrease) increase in long-term other liabilities (51,779) 13,453 6,760
------------ ------------ ------------
Net cash (used in) provided by financing
activities (389,571) 377,198 256,518
------------ ------------ ------------
Effect of exchange rate changes on cash (1,177) 704 (140)
------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents 54,883 141,913 (16,411)
Cash and cash equivalents at beginning of year 173,167 31,254 47,665
------------ ------------ ------------
Cash and cash equivalents at end of year $ 228,050 173,167 31,254
============ ============ ============
See accompanying notes to consolidated financial statements.
36
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 and
Gabon. 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.
37
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. Internal costs
incurred that are directly identified with acquisition, exploration and
development activities undertaken by Devon for its own account, and which are
not related to production, general corporate overhead or similar activities are
also capitalized. For the years 2000, 1999 and 1998, such internal costs
capitalized totaled $61.8 million, $28.9 million and $14.8 million,
respectively.
Unproved properties are excluded from amortized capitalized costs until
it is determined whether or not proved reserves can be assigned to such
properties. Devon assesses its unproved properties for impairment annually.
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 six thousand
cubic feet of natural gas to one barrel of oil. Depletion is calculated using
the capitalized costs plus the estimated future expenditures (based on current
costs) to be incurred in developing proved reserves, and the estimated
dismantlement and abandonment costs, net of estimated salvage values. 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. All costs related to production activities, including workover costs
incurred solely to maintain or increase levels of production from an existing
completion interval, are charged to expense as incurred.
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 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."
38
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 goodwill amortization was $57.4 million and $16.1 million
at December 31, 2000 and 1999, respectively.
Revenue Recognition and Gas Balancing
Oil and gas revenues are recognized when sold. 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 financial instruments
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 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
39
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.
Devon adopted the provisions of SFAS 133, as amended, in the first
quarter of the year ending December 31, 2001. In accordance with the transition
provisions of SFAS 133, Devon recorded a net-of-tax cumulative-effect-type
adjustment of $36.6 million in accumulated other comprehensive loss to recognize
at fair value all derivatives that are designated as cash-flow hedging financial
instruments. Additionally, Devon recorded a net-of-tax cumulative-effect-type
adjustment to net earnings for a $49.5 million gain related to the fair value of
financial instruments that do not qualify as hedges. This gain included $46.2
million related to the option embedded in Devon's debentures that are
exchangeable into shares of Chevron Corporation common stock.
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 2000, Enron Capital and Trade Resource Corporation accounted for 20%
of Devon's combined oil, gas and natural gas liquids sales. 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.
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.
40
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) and if Devon's zero coupon
convertible senior debentures were converted to common stock.
The following table reconciles the net earnings and common shares
outstanding used in the calculations of basic and diluted earnings per share for
2000. The diluted loss per share calculations for 1999 and 1998 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.) Therefore,
the diluted loss per share amounts for 1999 and 1998 reported in the
accompanying consolidated statements of operations are the same as the basic
loss per share amounts.
NET EARNINGS WEIGHTED
APPLICABLE AVERAGE NET
TO COMMON COMMON SHARES EARNINGS
STOCKHOLDERS OUTSTANDING PER SHARE
------------ ------------- ---------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31, 2000:
Basic earnings per share $720,607 127,421 $5.66
Dilutive effect of:
Potential common shares issuable upon conversion
of senior convertible debentures (the increase in net
earnings is net of income tax expense of $2,755,000) 4,309 2,248
Potential common shares issuable upon the exercise
of outstanding stock options -- 2,061
---------- --------
Diluted earnings per share $ 724,916 131,730 $5.50
========== ======== =====
Options to purchase approximately 1.0 million shares of Devon's common
stock with exercise prices ranging from $55.54 per share to $89.66 per share
(with a weighted average price of $66.64 per share) were outstanding at December
31, 2000, but were not included in the computation of diluted earnings per share
for 2000 because the options' exercise price exceeded the average market price
of Devon's common stock during the year. The excluded options for 2000 expire
between February 12, 2001 and June 1, 2010. All options were excluded from the
diluted earnings per share calculations for 1999 and 1998.
41
Comprehensive Loss
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, 2000, 1999 and 1998, and
changes during each of the years then ended, is presented in the following
table.
FOREIGN MINIMUM UNREALIZED
CURRENCY PENSION LOSSES ON
TRANSLATION LIABILITY MARKETABLE
ADJUSTMENTS ADJUSTMENTS SECURITIES TOTAL
----------- ----------- ---------- --------
(IN THOUSANDS)
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)
2000 activity (10,213) 1,346 (17,608) (26,475)
Deferred taxes -- (524) 6,844 6,320
-------- -------- -------- --------
2000 activity, net of deferred taxes (10,213) 822 (10,764) (20,155)
-------- -------- -------- --------
Balance as of December 31, 2000 $(37,939) (138) (47,320) (85,397)
======== ======== ======== ========
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 2000, 1999 and 1998 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 2000, 1999 and 1998 were $0.17,
$0.14 and $0.10, 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.
42
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.
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.
Reclassification
Certain of the 1999 and 1998 amounts in the accompanying consolidated
financial statements have been reclassified to conform to the 2000 presentation.
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.
During 2000, Devon recorded a pre-tax charge of $60.4 million ($37.2
million net of tax) for direct costs related to the Santa Fe Snyder merger.
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
43
price and the 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.
(IN THOUSANDS,
EXCEPT SHARE PRICE)
-------------------
Calculation and 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
============
Additionally, $346.9 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 $346.9 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.)
44
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.
(IN THOUSANDS,
EXCEPT SHARE PRICE)
-------------------
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
============
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.
45
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 (Unaudited)
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 does not include 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 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
46
$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.
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 also includes the related $207.0 million
after-tax extraordinary loss resulting from the early
extinguishment of debt.
o The 1999 pro forma financial information includes a $4.2
million extraordinary loss recorded by Santa Fe Snyder. This
loss related to the early extinguishment of debt.
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.
47
PRO FORMA INFORMATION
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998
------------ ------------
(DOLLARS IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
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 196,990 206,421
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 2,005,895 2,111,279
------------ ------------
Earnings (loss) before income tax expense (benefit) and (315,799) (443,447)
extraordinary item
INCOME TAX EXPENSE (BENEFIT)
Current 23,261 (1,076)
Deferred (107,680) (121,131)
------------ ------------
Total income tax expense (benefit) (84,419) (122,207)
------------ ------------
Loss before extraordinary item (231,380) (321,240)
Extraordinary loss (4,200) (206,963)
------------ ------------
Net loss (235,580) (528,203)
Preferred stock dividends 9,736 5,625
------------ ------------
Net loss applicable to common stockholders $ (245,316) (533,828)
============ ============
Net loss before extraordinary item per average common
share outstanding - basic and diluted $ (2.20) (3.04)
============ ============
Net loss per average common share
outstanding - basic and diluted $ (2.24) (4.97)
============ ============
Weighted average common shares outstanding - basic 109,656 107,371
============ ============
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
48
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, 2000, approximately 13.1 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.
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 a
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 2000, 1999 and 1998, the San Juan Basin Transaction added
approximately $12.3 million, $7.6 million and $8.4 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 had previously 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 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 and $6.8 million in 1999 and 1998,
respectively, which were added to the repurchase liability. The actual
repurchase price as of September 30, 2000, was approximately $36.3 million.
4. SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments for interest in 2000, 1999 and 1998 were approximately
$155.1 million, $115.6 million and $45.6 million, respectively. Cash payments
for federal, state and foreign income taxes in 2000, 1999 and 1998 were
approximately $81.8 million, $15.8 million and $19.4 million, respectively.
49
The 1999 PennzEnergy merger and Snyder merger involved non-cash
consideration as presented below:
1999
--------------
(IN THOUSANDS)
Value of common stock issued $ 1,130,269
Value of preferred stock issued 150,000
Employee stock options assumed 18,295
Liabilities assumed 2,259,174
Deferred tax liability created 474,306
------------
Fair value of assets acquired with
non-cash consideration $ 4,032,044
=============
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).
5. ACCOUNTS RECEIVABLE
The components of accounts receivable included the following:
DECEMBER 31,
------------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
Oil, gas and natural gas liquids
revenue accruals $ 438,304 218,462 74,660
Joint interest billings 122,778 66,658 33,136
Other 41,013 34,585 31,262
------------ ------------ ------------
602,095 319,705 139,058
Allowance for doubtful accounts (3,847) (3,700) (2,000)
------------ ------------ ------------
Net accounts receivable $ 598,248 316,005 137,058
============ ============ ============
50
6. PROPERTY AND EQUIPMENT
Property and equipment included the following:
DECEMBER 31,
------------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
Oil and gas properties:
Subject to amortization $ 9,169,593 8,125,886 4,584,676
Not subject to amortization:
Acquired in 2000 74,164 -- --
Acquired in 1999 122,431 134,966 --
Acquired in 1998 44,833 56,922 65,702
Acquired prior to 1998 73,832 109,297 147,875
Accumulated depreciation, depletion
and amortization (4,752,670) (4,129,824) (3,204,775)
------------ ------------ ------------
Net oil and gas properties 4,732,183 4,297,247 1,593,478
------------ ------------ ------------
Other property and equipment 224,499 164,939 55,958
Accumulated depreciation and amortization (47,146) (38,766) (25,908)
------------ ------------ ------------
Net other property and equipment 177,353 126,173 30,050
------------ ------------ ------------
Property and equipment, net of accumulated
depreciation, depletion and amortization $ 4,909,536 4,423,420 1,623,528
============ ============ ============
The costs not subject to amortization relate to unproved properties,
none of which are individually significant. Subject to industry conditions,
evaluation of these properties is expected to be completed within five years.
Depreciation, depletion and amortization of property and equipment
consisted of the following components:
YEAR ENDED DECEMBER 31,
---------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
Depreciation, depletion and amortization
of oil and gas properties $ 662,890 390,117 230,419
Depreciation and amortization of other
property and equipment 22,974 13,660 12,564
Amortization of other assets 7,476 2,598 161
------------ ------------ ------------
Total expense $ 693,340 406,375 243,144
============ ============ ============
51
7. LONG-TERM DEBT AND RELATED EXPENSES
A summary of Devon's long-term debt is as follows:
DECEMBER 31,
------------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
Borrowings under credit facilities with banks $ 146,652 645,141 411,271
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 --
Zero coupon convertible senior debentures
exchangeable into shares of Devon
Energy Corp. common stock, 3.875% due
June 27, 2020 359,689 -- --
Other debentures:
10.25% due November 1, 2005 250,000 250,000 --
10.125% due November 15, 2009 200,000 200,000 --
11.00% due May 15, 2004 -- -- 100,000
Premium (discount) on debentures 33,375 37,467 (400)
Senior notes:
8.05% due June 15, 2004 124,881 125,000 --
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 (1,074) (1,400) --
------------ ------------ ------------
2,048,836 2,416,521 735,871
Less amount classified as current -- -- --
------------ ------------ ------------
Long-term debt $ 2,048,836 2,416,521 735,871
============ ============ ============
Maturities of long-term debt as of December 31, 2000, excluding the
$32.3 million of premiums net of discounts, are as follows (in thousands):
2001 $ --
2002 7,333
2003 7,333
2004 132,213
2005 257,332
2006 and thereafter 1,612,324
-------------
Total $ 2,016,535
=============
52
Credit Facilities with Banks
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 include a U.S.
facility of $725 million (the "U.S. Facility") and a Canadian facility of $275
million (the "Canadian Facility").
The Credit Facilities replaced the prior separate facilities of Devon
and Santa Fe Snyder. Prior to the August 2000 merger, Devon and Santa Fe Snyder
each had their own unsecured credit facilities. 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. Santa Fe Snyder's credit facilities prior
to the merger aggregated $600 million.
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. The weighted average interest rate on the $146.7
million outstanding under the Credit Facilities at December 31, 2000, was 6.07%.
The average interest rate on bank debt outstanding under the previous facilities
at December 31, 1999 and 1998 was 6.85% and 6.28%, respectively.
The agreements governing the Credit Facilities contain certain
covenants and restrictions, including a maximum debt-to-capitalization ratio. At
December 31, 2000, Devon was in compliance with such covenants and restrictions.
53
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 and mature August 15, 2008. The exchangeable
debentures are callable beginning August 15, 2000, initially at 104.0% of
principal and at prices declining to 100.5% of principal on or after August 15,
2007. 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, 2000, 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.
Senior Notes
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
54
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.
In September 2000, Devon, as required under the $125 million senior
note agreement due to a "change of control", made a tender offer to repurchase
the senior notes at a premium of 101.000%. As a result of this tender offer,
$119,000 of senior notes were redeemed at a total cost to Devon of approximately
$120,000.
Zero Coupon Convertible Debentures
In June 2000, Devon privately sold zero coupon convertible senior
debentures. The debentures were sold at a price of $464.13 per debenture with a
yield to maturity of 3.875% per annum. Each of the 760,000 debentures is
convertible into 5.7593 shares of Devon common stock. Devon may call the
debentures at any time after five years, and a debenture holder has the right to
require Devon to repurchase the debentures 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 debentures to pay
down other domestic long-term debt.
Interest Expense
Following are the components of interest expense for the years 2000,
1999 and 1998:
YEAR ENDED DECEMBER 31,
------------------------------------------
2000 1999 1998
---------- ---------- ----------
(IN THOUSANDS)
Interest based on debt outstanding $ 157,028 108,064 43,114
Amortization of debt premium, net (3,781) (1,328) --
Facility and agency fees 2,696 1,930 932
Amortization of capitalized loan costs 1,467 1,583 556
Capitalized interest (3,239) (1,925) (1,100)
Other 158 1,289 30
---------- ---------- ----------
Total interest expense $ 154,329 109,613 43,532
========== ========== ==========
55
Deferred Effect of Changes in Foreign Currency Exchange Rate on Long-term Debt
Until mid-January 2000, the 6.76 % and 6.79% 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 declined in 2000 and 1998 and
increased in 1999. Therefore, $2.4 million of increased expense was recorded in
2000, $13.2 million of reduced expense was recorded in 1999, and $16.1 million
of increased expense was recorded in 1998.
8. INCOME TAXES
At December 31, 2000, Devon had the following carryforwards available
to reduce future income taxes:
YEARS OF CARRYFORWARD
TYPES OF CARRYFORWARD EXPIRATION AMOUNTS
---------- ------------
(IN THOUSANDS)
Net operating loss - U.S. federal 2008 - 2014 $ 344,038
Net operating loss - various states 2002 - 2014 $ 37,357
Net operating loss - Canada 2001 - 2007 $ 2,180
Minimum tax credits Indefinite $ 84,991
All of the carryforward amounts shown above have been utilized for
financial purposes to reduce deferred taxes.
56
The earnings (loss) before income taxes and the components of income tax
expense (benefit) for the years 2000, 1999 and 1998 were as follows:
YEAR ENDED DECEMBER 31,
-----------------------------------------
2000 1999 1998
---------- ---------- ----------
(IN THOUSANDS)
Earnings (loss) before income taxes:
U.S $ 872,455 (313,101) (274,150)
Canada 156,085 57,402 19,958
International 113,440 56,321 (107,800)
---------- ---------- ----------
Total $1,141,980 (199,378) (361,992)
========== ========== ==========
Current income tax expense (benefit):
U.S. federal $ 106,742 12,544 (6,399)
Various states 6,015 2,804 (1,189)
Canada 2,268 2,908 1,975
Other 15,768 4,800 1,900
---------- ---------- ----------
Total current tax expense (benefit) 130,793 23,056 (3,713)
---------- ---------- ----------
Deferred income tax expense (benefit):
U.S. federal 151,832 (119,286) (88,824)
Various states 33,399 (495) (4,836)
Canada 67,318 26,654 11,166
Other 28,296 20,637 (39,900)
---------- ---------- ----------
Total deferred tax expense (benefit) 280,845 (72,490) (122,394)
---------- ---------- ----------
Total income tax expense (benefit) $ 411,638 (49,434) (126,107)
========== ========== ==========
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:
YEAR ENDED DECEMBER 31,
----------------------------------------
2000 1999 1998
---------- ---------- ----------
U.S. statutory tax (benefit) rate 35% (35)% (35)%
Benefit from disposition of certain
foreign assets (11) -- --
Non-deductible expenses 3 3 3
Nonconventional fuel source credits (2) (3) (1)
State income taxes 2 1 (1)
Taxation on foreign operations 5 7 2
Other 4 2 (3)
---------- ---------- ----------
Effective income tax (benefit) rate 36% (25)% (35)%
========== ========== ==========
57
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax assets and liabilities at December 31, 2000, 1999
and 1998 are presented below:
DECEMBER 31,
------------------------------------------
2000 1999 1998
---------- ---------- ----------
(IN THOUSANDS)
Deferred tax assets:
Net operating loss carryforwards $ 122,843 207,322 48,418
Minimum tax credit carryforwards 84,991 88,447 16,900
Production payments -- 21,527 19,105
Long-term debt 17,176 17,583 --
Other 95,283 50,618 20,388
---------- ---------- ----------
Total gross deferred tax assets 320,293 385,497 104,811
Less valuation allowance 100 100 100
---------- ---------- ----------
Net deferred tax assets 320,193 385,397 104,711
---------- ---------- ----------
Deferred tax liabilities:
Property and equipment, principally due
to differences in depreciation, and
the expensing of intangible drilling
costs for tax purposes (687,473) (500,156) (49,256)
Chevron Corporation common stock (166,596) (172,631) --
Other (83,971) (31,789) (469)
---------- ---------- ----------
Total deferred tax liabilities (938,040) (704,576) (49,725)
---------- ---------- ----------
Net deferred tax (liability) asset $ (617,847) (319,179) 54,986
========== ========== ==========
As shown in the above table, Devon has recognized $320.2 million of net
deferred tax assets as of December 31, 2000. Such amount consists primarily of
$207.8 million of various carryforwards available to offset future income taxes.
The 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 2002 and 2014, Canadian
carryforwards which expire primarily between 2001 and 2007, 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 2001 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,
2000, related to depletion carryforwards acquired in a 1994 merger.
58
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 equated 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.
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.
59
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 2000, 13.1 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, 2000, 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, 2000, there were 109,000 and 487,540 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.
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, 2000, there were
60
3,306,329 options outstanding under the 1997 Plan. There were 6,225,949 options
available for future grants as of December 31, 2000.
In addition to the stock options outstanding under the 1988 Plan, 1993
Plan and 1997 Plan, there were approximately 1,744,409, 1,630,123 and 78,553
stock options outstanding at the end of 2000 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, 1998, 1999 and 2000, and changes during each of the years then ended, is
presented below.
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------ ----------------------------
WEIGHTED
AVERAGE
NUMBER EXERCISE NUMBER EXERCISE
OUTSTANDING PRICE EXERCISABLE PRICE
----------- -------- ----------- --------
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
========= ========
Options granted 1,624,800 $ 51.430
Options exercised (2,488,756) $ 33.106
Options forfeited (333,991) $ 60.354
----------
Balance at December 31, 2000 7,355,954 $ 41.843 6,024,796 $ 40.718
========== ========= ========
The weighted average fair values of options granted during 2000, 1999
and 1998 were $28.73, $12.80 and $13.44, 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 2000,
1999 and 1998, respectively: risk-free interest rates of 5.5%, 6.0% and 5.0%;
dividend yields of 0.4%, 0.5% and 0.4%; expected lives of 5, 5 and 5 years; and
volatility of the price of the underlying common stock of 40.0%, 35.2% and
31.7%.
61
The following table summarizes information about Devon's stock options
which were outstanding, and those which were exercisable, as of December 31,
2000:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------------------- -----------------------------
WEIGHTED WEIGHTED WEIGHTED
RANGE OF AVERAGE AVERAGE AVERAGE
EXERCISE NUMBER REMAINING EXERCISE NUMBER EXERCISE
PRICES OUTSTANDING LIFE PRICE EXERCISABLE PRICE
--------------- ----------- ---------- -------- ----------- --------
$ 8.375-$26.501 886,899 2.98 Years $ 22.732 881,065 $ 22.719
$28.830-$33.381 1,892,214 6.52 Years $ 30.691 1,612,472 $ 30.705
$34.375-$39.773 1,288,365 6.10 Years $ 36.550 1,263,100 $ 36.554
$40.125-$49.950 522,150 5.56 Years $ 46.067 506,884 $ 46.017
$50.142-$59.813 2,146,853 7.75 Years $ 53.072 1,155,202 $ 54.212
$60.150-$89.660 619,473 4.84 Years $ 71.797 606,073 $ 72.050
---------- ----------
7,355,954 6.17 Years $ 41.843 6,024,796 $ 40.718
========== ==========
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 2000, 1999 and 1998
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.
YEAR ENDED DECEMBER 31,
---------------------------------------------
2000 1999 1998
--------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Net earnings (loss) available to common shareholders
As reported $ 720,607 (157,795) (235,885)
Pro forma $ 701,852 (173,005) (252,070)
Net earnings (loss) per share available to common
shareholders:
As reported:
Basic $ 5.66 (1.68) (3.32)
Diluted $ 5.50 (1.68) (3.32)
Pro forma:
Basic $ 5.51 (1.85) (3.55)
Diluted $ 5.36 (1.85) (3.55)
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
62
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.
11. FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair
values of Devon's financial instruments at December 31, 2000, 1999 and 1998.
2000 1999 1998
--------------------------- -------------------------- -----------------------
CARRYING FAIR CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE AMOUNT VALUE
------------ ----------- ----------- ----------- -------- --------
(IN THOUSANDS)
Investments $ 606,117 606,117 634,281 634,281 1,930 1,930
Oil and gas price hedge $ -- (57,560) -- (9,540) -- 1,988
agreements
Foreign exchange hedge $ -- (533) -- (2,535) -- (9,310)
agreements
Long-term debt
(including current portion) $ (2,048,836) (2,049,779) (2,416,521) (2,400,334) (735,871) (758,075)
TCP Securities $ -- -- -- -- (149,500) (171,400)
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, 2000, 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) an internal discounted cash flow
calculation, (b) quotes obtained from the counterparty to the hedge agreement or
(c) 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.
63
The following table covers Devon's notional volumes and pricing on open
natural gas hedging instruments as of December 31, 2000:
YEAR OF PRODUCTION
-------- --------
2001 2002
-------- --------
Volumes (billion British thermal units) 14,027 3,333
Average price to be received $ 2.18 2.52
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
F.E.R.C.'s Gas Market Report" ("Inside FERC") for the Rocky Mountains.
In addition to the above gas hedging instruments, Devon also had a
natural gas basis swap in effect as of December 31, 2000. In this basis swap,
which covers 20,000 MMBtus per day, Devon owes the counterparty the applicable
monthly Colorado Interstate Gas Co. index price as published by Inside FERC,
while the counterparty owes Devon the average NYMEX 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.
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, 2000, Devon had open foreign currency hedging
instruments in which it will sell $10 million in 2001 at average
Canadian-to-U.S. dollar exchange rates of $0.7102. Under this agreement, Devon
will buy the same amount of dollars at the floating exchange rate.
Devon's 1999 and 1998 consolidated balance sheets include deferred
revenues of $0.4 million and $1.0 million, respectively, for gains realized on
the early termination of commodity and foreign currency hedging instruments in
prior years.
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.
64
In 2000, Devon established a defined benefit postretirement plan, which
is unfunded, and covers substantially all current employees including former
Santa Fe Snyder and PennzEnergy employees who remained with Devon. Additionally,
Devon assumed responsibility for the PennzEnergy sponsored defined benefit
postretirement plans, which are unfunded. 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.
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, 2000, 1999
and 1998.
PENSION BENEFITS OTHER RETIREMENT BENEFITS
------------------------------------- -------------------------------------
2000 1999 1998 2000 1999 1998
--------- --------- --------- --------- --------- ---------
(IN THOUSANDS)
Change in benefit obligation:
Benefit obligation at beginning of year $ 155,569 63,841 53,859 $ 37,860 8,100 6,600
Service cost 6,736 4,937 2,685 809 838 400
Interest cost 11,283 6,464 4,035 2,330 1,249 500
Participant contributions -- -- -- 147 -- 100
Amendments 4,303 -- 293 (1,985) -- --
Mergers and acquisitions -- 87,751 -- -- 28,659 --
Curtailment gain (3,037) -- -- (346) -- --
Actuarial (gain) loss (2,963) (3,525) 5,573 (3,153) 600 1,000
Benefits paid (7,290) (3,899) (2,604) (3,520) (1,586) (500)
--------- --------- --------- --------- --------- ---------
Benefit obligation at end of year 164,601 155,569 63,841 32,142 37,860 8,100
--------- --------- --------- --------- --------- ---------
Change in plan assets:
Fair value of plan assets at
beginning of year 157,894 41,531 43,136 -- -- --
Actual return on plan assets 2,574 14,808 113 -- -- --
PennzEnergy merger -- 104,181 -- -- -- --
Employer contributions 1,664 1,273 886 3,373 1,486 400
Participant contributions -- -- -- 147 100 100
Benefits paid (7,290) (3,899) (2,604) (3,520) (1,586) (500)
--------- --------- --------- --------- --------- ---------
Fair value of plan assets at end of year 154,842 157,894 41,531 -- -- --
--------- --------- --------- --------- --------- ---------
Funded status (9,759) 2,325 (22,310) (32,142) (37,860) (8,100)
Unrecognized net actuarial (gain) loss 9,888 (2,723) 9,130 (2,199) 800 200
Unrecognized prior service cost 1,570 1,966 2,322 (1,201) -- --
Unrecognized net transition (asset) obligation (6,331) (400) (500) 1,152 2,100 2,300
Other -- 100 -- -- 100 100
--------- --------- --------- --------- --------- ---------
Net amount recognized $ (4,632) 1,268 (11,358) $ (34,390) (34,860) (5,500)
========= ========= ========= ========= ========= =========
The net amounts recognized in the
consolidated
balance sheets consist of:
(Accrued) prepaid benefit cost $ (4,632) 1,268 (11,358) $ (34,390) (34,860) (5,500)
Additional minimum liability (735) (3,110) (2,987) -- -- --
Intangible asset 508 1,537 1,808 -- -- --
Accumulated other comprehensive loss 227 1,573 1,179 -- -- --
--------- --------- --------- --------- --------- ---------
Net amount recognized $ (4,632) 1,268 (11,358) $ (34,390) (34,860) (5,500)
========= ========= ========= ========= ========= =========
Assumptions:
Discount rate 7.65% 7.34% 6.69% 7.65% 7.32% 6.75%
Expected return on plan assets 8.50% 8.37% 9.35% N/A N/A N/A
Rate of compensation increase 5.00% 4.88% 4.84% 5.00% 4.75% 4.75%
The benefit obligation for the defined benefit pension plans with
benefit obligations in excess of assets was $87.0 million as of December 31,
2000. The plan assets for these plans at December 31, 2000 totaled $49.9
million.
65
Net periodic benefit cost included the following components:
OTHER POSTRETIREMENT
PENSION BENEFITS BENEFITS
-------------------------------- -------------------------------
2000 1999 1998 2000 1999 1998
-------- -------- -------- -------- -------- --------
(IN THOUSANDS)
Service cost $ 6,736 4,937 2,685 $ 809 838 400
Interest cost 11,283 6,464 4,035 2,330 1,249 500
Expected return on plan assets (13,247) (6,900) (3,932) -- -- --
Amortization of prior service cost 289 256 256 (37) -- --
Amortization of transition obligation (52) -- -- 170 200 200
Recognized net actuarial (gain) loss 294 320 11 (207) -- --
-------- -------- -------- -------- -------- --------
Net periodic benefit cost $ 5,303 5,077 3,055 $ 3,065 2,287 1,100
======== ======== ======== ======== ======== ========
For measurement purposes, a 10% 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 2005 and
remain at that 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:
ONE-PERCENTAGE ONE-PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
(IN THOUSANDS)
Effect on total of service and interest cost components for 2000 $ 230 $ (204)
Effect on year-end 2000 postretirement benefit obligation $ 1,062 $ (1,009)
Devon has incurred 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 $12.7
million and $2.5 million at the end of 2000 and 1999, respectively.
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 $5.0 million, $4.3 million and $2.3 million for the years ended December
31, 2000, 1999 and 1998, 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.
66
During the years 2000, 1999 and 1998, Devon's combined contributions to
the Canadian defined contribution plan and the Canadian savings plan were $2.1
million, $1.9 million and $1.8 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, 2000, 1999 and 1998,
Devon's liability with respect to the plan totaled $0.4 million, $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. 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, 2000, Devon's consolidated balance sheet
included $7.8 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.
67
Royalty Matters
More than 30 oil companies, including Devon, are involved in disputes
in which it is alleged that such companies and related parties underpaid
royalty, overriding royalty and working interests owners 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. To avoid expensive and protracted litigation, certain
parties, including Devon, have entered into a global settlement agreement which
provides for a settlement of all claims of all members of the settlement class.
The court held a fairness hearing and issued an Amended Final Judgment approving
the settlement on September 10, 1999. However, certain entities have appealed
their objections to the settlement. Devon's share of the proposed settlement,
which was accrued at December 31, 2000, is not material to its financial
position, results of operations or liquidity.
Also, pending in federal court in Texas is a similar suit alleging
underpaid royalties to the United States in connection with natural gas and
natural gas liquids produced and sold from United States owned and/or controlled
lands. The claims were filed by private litigants against Devon and numerous
other producers, under the federal False Claims Act. The United States served
notice of its intent to intervene as to certain defendants, but not Devon. Devon
and certain other defendants are challenging the constitutionality of whether a
claim under the federal False Claims Act can be maintained absent government
intervention. Devon believes that it has acted reasonably and paid royalties in
good faith. Devon does not currently believe that it is subject to material
exposure in association with this litigation. As a result, Devon's monetary
exposure in this suit is not expected to be material.
Maersk Rig Contract
In December 1997, the working interest owner partner of Pennzoil
Venezuela Corporation, S.A. ("PVC"), a subsidiary of Devon as a result of the
PennzEnergy merger, entered into a contract 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 70/80 in Lake
Maracaibo, Venezuela. The rig was assembled and delivered by Maersk 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. The contract, which
expires October 1, 2001, provides for early termination, with a charge for such
termination which is currently estimated at $42,000 per day with certain
escalation factors for the balance of the term. As of December 31, 2000, Devon's
consolidated balance sheet included accrued liabilities, reflected in "Other
liabilities," for the expected cost to terminate/settle the contract. 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 the contract.
68
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, 2000:
YEAR ENDING DECEMBER 31, (IN THOUSANDS)
------------------------
2001 $ 14,394
2002 12,279
2003 11,513
2004 10,779
2005 10,293
Thereafter 20,466
--------
Total minimum lease payments required $ 79,724
========
Total rental expense for all operating leases is as follows for the
years ended December 31:
(IN THOUSANDS)
2000 $ 18,564
1999 $ 24,204
1998 $ 18,319
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 2000, the Trust had received
support payments totaling $4.2 million and Devon had recouped all such 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.
69
At December 31, 2000 and 1999, accounts payable as shown on the
accompanying consolidated balance sheets included $4.1 million and $3.4 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 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 and 1998, Devon reduced the carrying value of its oil and
gas properties by $476.1 million and $422.5 million, respectively, due to the
full cost ceiling limitations. The after-tax effect of these reductions in 1999
and 1998 were $309.7 million and $280.8 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:
TOTAL
YEAR ENDED DECEMBER 31,
-----------------------------------------
2000 1999 1998
---------- ---------- -----------
(IN THOUSANDS)
Property acquisition costs:
Proved, excluding deferred income taxes $ 291,355 3,002,269 245,467
Deferred income taxes -- 131,700 21,382
---------- ---------- -----------
Total proved, including deferred income taxes $ 291,355 3,133,969 266,849
========== ========== ===========
Unproved, excluding deferred income taxes:
Business combinations -- 83,505 5,278
Other acquisitions 55,344 40,583 55,827
Deferred income taxes -- -- 661
---------- ---------- -------
Total unproved, including deferred income taxes $ 55,344 124,088 61,766
========== ========== =======
Exploration costs $ 212,719 157,706 176,014
Development costs $ 636,379 336,126 294,105
70
DOMESTIC
-----------------------------------------
YEAR ENDED DECEMBER 31,
-----------------------------------------
2000 1999 1998
---------- ---------- -------
(IN THOUSANDS)
Property acquisition costs:
Proved, excluding deferred income taxes $ 177,072 2,670,237 87,549
Deferred income taxes -- 131,700 --
---------- ---------- -------
Total proved, including deferred income taxes $ 177,072 2,801,937 87,549
========== ========== =======
Unproved, excluding deferred income taxes:
Business combinations -- 81,755 --
Other acquisitions 34,805 27,728 40,364
Deferred income taxes -- -- --
---------- ---------- -------
Total unproved, including deferred income taxes $ 34,805 109,483 40,364
========== ========== =======
Exploration costs $ 117,119 88,171 71,486
Development costs $ 466,090 228,095 149,286
CANADA
--------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------
2000 1999 1998
------- --------- --------
(IN THOUSANDS)
Property acquisition costs:
Proved, excluding deferred income taxes $69,736 29,532 107,818
Deferred income taxes -- -- 21,382
------- --------- --------
Total proved, including deferred income taxes $69,736 29,532 129,200
======= ========= =======
Unproved, excluding deferred income taxes:
Business combinations -- -- 5,278
Other acquisitions 16,977 9,155 10,263
Deferred income taxes -- -- 661
------- --------- ----------
Total unproved, including deferred income taxes $16,977 9,155 16,202
======= ========= ========
Exploration costs $54,769 37,197 49,928
Development costs $56,654 29,811 75,119
INTERNATIONAL
----------------------------------------
YEAR ENDED DECEMBER 31,
----------------------------------------
2000 1999 1998
---------- --------- -------
(IN THOUSANDS)
Property acquisition costs:
Proved, excluding deferred income taxes $ 44,547 302,500 50,100
Deferred income taxes -- -- --
---------- --------- -------
Total proved, including deferred income taxes $ 44,547 302,500 50,100
========== ========= =======
Unproved, excluding deferred income taxes:
Business combinations -- 1,750 --
Other acquisitions 3,562 3,700 5,200
Deferred income taxes -- -- --
---------- --------- -------
Total unproved, including deferred income taxes $ 3,562 5,450 5,200
========== ========= =======
Exploration costs $ 40,831 32,338 54,600
Development costs $ 113,635 78,220 69,700
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 $61.8
million, $28.9 million and $14.8 million in the years 2000, 1999 and 1998,
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
71
tax-free nature of the PennzEnergy merger in August 1999, additional deferred
tax liabilities of $346.9 million were recorded in 1999 and allocated to
goodwill.
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.
TOTAL
-----------------------------------------------------
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
2000 1999 1998
--------------- --------------- ---------------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales $ 2,718,445 1,256,872 681,978
Production and operating expenses (597,333) (377,472) (274,618)
Depreciation, depletion and amortization (662,890) (390,117) (230,419)
Amortization of goodwill (41,332) (16,111) --
Reduction of carrying value of oil and gas -- (476,100) (422,500)
properties
Income tax (expense) benefit (571,755) (24,984) 65,515
--------------- --------------- ---------------
Results of operations for oil and gas producing
activities $ 845,135 (27,912) (180,044)
=============== =============== ===============
Depreciation, depletion and amortization per
equivalent barrel of production $ 5.48 4.46 3.74
=============== =============== ===============
DOMESTIC
-----------------------------------------------------
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
2000 1999 1998
--------------- --------------- ---------------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales $ 2,167,571 891,670 417,313
Production and operating expenses (462,849) (254,077) (164,612)
Depreciation, depletion and amortization (541,174) (293,841) (154,127)
Amortization of goodwill (41,303) (16,106) --
Reduction of carrying value of oil and gas
properties -- (463,700) (301,400)
Income tax (expense) benefit (445,783) 37,786 63,630
--------------- --------------- ---------------
Results of operations for oil and gas producing
activities $ 676,462 (98,268) (139,196)
=============== =============== ===============
Depreciation, depletion and amortization per
equivalent barrel of production $ 5.73 4.98 4.41
=============== =============== ===============
72
CANADA
-----------------------------------------------------
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
2000 1999 1998
--------------- --------------- ---------------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales $ 303,537 204,501 169,965
Production and operating expenses (64,773) (62,595) (58,506)
Depreciation, depletion and amortization (64,094) (64,514) (43,392)
Reduction of carrying value of oil and gas
properties -- -- --
Income tax (expense) benefit (79,363) (37,736) (37,615)
--------------- --------------- ---------------
Results of operations for oil and gas producing
activities $ 95,307 39,656 30,452
=============== =============== ===============
Depreciation, depletion and amortization per
equivalent barrel of production $ 4.05 3.56 2.41
=============== =============== ===============
INTERNATIONAL
-----------------------------------------------------
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
2000 1999 1998
--------------- --------------- ---------------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales $ 247,337 160,701 94,700
Production and operating expenses (69,711) (60,800) (51,500)
Depreciation, depletion and amortization (57,622) (31,762) (32,900)
Amortization of goodwill (29) (5) --
Reduction of carrying value of oil and gas
properties -- (12,400) (121,100)
Income tax (expense) benefit (46,609) (25,034) 39,500
--------------- --------------- ---------------
Results of operations for oil and gas producing
activities $ 73,366 30,700 (71,300)
=============== =============== ===============
Depreciation, depletion and amortization per
equivalent barrel of production $ 5.38 3.06 3.78
=============== =============== ===============
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."
73
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, 2000. Approximately 80%, 98% and 96%, of the respective
year-end 2000, 1999 and 1998 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 2000 and 1999
Canadian proved reserves were calculated by the independent petroleum
consultants Paddock Lindstrom & Associates. All of the year-end 1998 Canadian
proved reserves were calculated by the independent petroleum consultants of
Paddock Lindstrom & Associates and AMH Group Ltd. All of the international
proved reserves other than Canada as of December 31, 2000 and 1999 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.
TOTAL
-------------------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
------------- ------------- -------------
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
Revisions of estimates (4,135) 99,223 3,312
Extensions and discoveries 33,939 601,317 6,041
Purchase of reserves 24,145 301,144 33
Production (42,561) (426,146) (7,400)
Sale of reserves (48,861) (66,981) (8,046)
------------- ------------- -------------
Proved reserves as of December 31, 2000 459,244 3,458,184 61,757
============= ============= =============
Proved developed reserves as of:
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
December 31, 2000 261,432 2,631,267 46,256
74
DOMESTIC
-------------------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
------------- ------------- -------------
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
Revisions of estimates (3,196) 100,844 4,296
Extensions and discoveries 20,430 504,977 5,092
Purchase of reserves 20,418 52,929 9
Production (28,562) (355,087) (6,702)
Sale of reserves (32,977) (56,742) (7,981)
------------- ------------- -------------
Proved reserves as of December 31, 2000 225,537 2,521,307 45,518
============= ============= =============
Proved developed reserves as of:
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
December 31, 2000 192,190 2,087,287 42,155
75
CANADA
-------------------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
------------- ------------- -------------
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
Revisions of estimates 2,872 (5,854) 343
Extensions and discoveries 2,787 64,566 571
Purchase of reserves 3,597 27,224 24
Production (4,760) (62,284) (682)
Sale of reserves (136) (6,361) (65)
------------- ------------- -------------
Proved reserves as of December 31, 2000 36,492 523,509 4,204
============= ============= =============
Proved developed reserves as of
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
December 31, 2000 29,721 507,703 4,072
76
INTERNATIONAL
-------------------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
------------- ------------- -------------
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
Revisions of estimates (3,811) 4,233 (1,327)
Extensions and discoveries 10,722 31,774 378
Purchase of reserves 130 220,991 --
Production (9,239) (8,775) (16)
Sale of reserves (15,748) (3,878) --
------------- ------------- -------------
Proved reserves as of December 31, 2000 197,215 413,368 12,035
============= ============= =============
Proved developed reserves as of
December 31, 1997 37,000 35,700 --
December 31, 1998 53,600 35,000 100
December 31, 1999 57,614 40,078 --
December 31, 2000 39,521 36,277 29
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:
TOTAL
-------------------------------------------------
DECEMBER 31,
-------------------------------------------------
2000 1999 1998
------------- ------------- -------------
(IN THOUSANDS)
Future cash inflows $ 40,594,130 18,494,929 5,114,485
Future costs:
Development (1,634,888) (1,506,678) (495,977)
Production (8,198,640) (6,270,893) (2,091,688)
Future income tax expense (9,087,923) (1,928,398) (196,475)
------------- ------------- -------------
Future net cash flows 21,672,679 8,788,960 2,330,345
10% discount to reflect timing of cash flows (9,200,492) (4,020,526) (916,757)
------------- ------------- -------------
Standardized measure of
discounted future net cash flows $ 12,472,187 4,768,434 1,413,588
============= ============= =============
77
DOMESTIC
-------------------------------------------------
DECEMBER 31,
-------------------------------------------------
2000 1999 1998
------------- ------------- -------------
(IN THOUSANDS)
Future cash inflows $ 29,143,762 11,362,918 2,718,030
Future costs:
Development (915,969) (750,497) (162,715)
Production (5,660,966) (3,894,271) (1,123,932)
Future income tax expense (6,345,941) (1,071,699) (117,912)
------------- ------------- -------------
Future net cash flows 16,220,886 5,646,451 1,313,471
10% discount to reflect timing of cash flows (6,591,538) (2,335,312) (503,689)
------------- ------------- -------------
Standardized measure of
discounted future net cash flows $ 9,629,348 3,311,139 809,782
============= ============= =============
CANADA
-------------------------------------------------
DECEMBER 31,
-------------------------------------------------
2000 1999 1998
------------- ------------- -------------
(IN THOUSANDS)
Future cash inflows $ 5,686,629 1,666,358 1,333,655
Future costs:
Development (84,492) (66,631) (85,362)
Production (616,605) (514,825) (491,256)
Future income tax expense (1,967,441) (204,290) (39,563)
------------- ------------- -------------
Future net cash flows 3,018,091 880,612 717,474
10% discount to reflect timing of cash flows (1,240,934) (320,722) (279,568)
------------- ------------- -------------
Standardized measure of
discounted future net cash flows $ 1,777,157 559,890 437,906
============= ============= =============
INTERNATIONAL
-------------------------------------------------
DECEMBER 31,
-------------------------------------------------
2000 1999 1998
------------- ------------- -------------
(IN THOUSANDS)
Future cash inflows $ 5,763,739 5,465,653 1,062,800
Future costs:
Development (634,427) (689,550) (247,900)
Production (1,921,069) (1,861,797) (476,500)
Future income tax expense (652,409) (39,000)
------------- ------------- -------------
(774,541)
Future net cash flows 2,433,702 2,261,897 299,400
10% discount to reflect timing of cash flows (1,368,020) (1,364,492) (133,500)
------------- ------------- -------------
Standardized measure of
discounted future net cash flows $ 1,065,682 897,405 165,900
============= ============= =============
Future cash inflows are computed by applying year-end prices (averaging
$23.77 per barrel of oil, adjusted for transportation and other charges, $8.04
per Mcf of gas and $29.80 per barrel of natural gas liquids at December 31,
2000) 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. Subsequent to December 31, 2000, the
price of natural gas has declined. The average price in February 2001 for gas
sold at market sensitive prices in North America was approximately one-third
below the year-end 2000 price.
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.
78
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.
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:
YEAR ENDED DECEMBER 31,
-------------------------------------------------
2000 1999 1998
------------- ------------- -------------
(IN THOUSANDS)
Beginning balance $ 4,768,434 1,413,588 1,680,676
Sales of oil, gas and natural gas
liquids, net of production costs (2,010,675) (879,400) (407,360)
Net changes in prices and
production costs 9,753,295 1,737,640 (743,193)
Extensions, discoveries, and improved
recovery, net of future
development costs 2,742,182 315,932 280,414
Purchase of reserves, net of future
development costs 618,134 2,881,881 223,055
Development costs incurred during
the period which reduced future
development costs 182,533 233,880 284,999
Revisions of quantity estimates 420,250 (62,821) (181,314)
Sales of reserves in place (818,602) (77,707) (36,565)
Accretion of discount 581,172 146,904 201,465
Net change in income taxes (4,221,575) (929,237) 305,317
Other, primarily changes in timing 457,039 (12,226) (193,906)
------------- ------------- -------------
Ending balance $ 12,472,187 4,768,434 1,413,588
============= ============= =============
17. SEGMENT INFORMATION
Devon manages its business by country. As such, Devon identifies its
segments based on geographic areas. Devon has three reportable 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 2000, 1999 and 1998. The revenues reported are all from external customers.
79
17. SEGMENT INFORMATION (CONTINUED)
U.S. CANADA INTERNATIONAL TOTAL
------------- ------------- ------------- -------------
(IN THOUSANDS)
AS OF DECEMBER 31, 2000:
Current assets $ 644,685 79,372 210,080 934,137
Property and equipment, net of accumulated 3,639,673 585,517 684,346 4,909,536
depreciation, depletion and amortization
Other assets 964,934 89 51,782 1,016,805
------------- ------------- ------------- -------------
Total assets $ 5,249,292 664,978 946,208 6,860,478
============= ============= ============= =============
Current liabilities 448,994 74,154 105,839 628,987
Long-term debt 1,902,184 146,652 -- 2,048,836
Deferred tax liabilities (assets) 536,935 68,578 21,313 626,826
Other liabilities 258,812 1,831 17,582 278,225
Stockholders' equity 2,102,367 373,763 801,474 3,277,604
------------- ------------- ------------- -------------
Total liabilities and stockholders' equity $ 5,249,292 664,978 946,208 6,860,478
============= ============= ============= =============
YEAR ENDED DECEMBER 31, 2000:
REVENUES
Oil sales $ 726,897 116,427 235,435 1,078,759
Gas sales 1,304,626 169,032 11,563 1,485,221
Natural gas liquids sales 136,048 18,078 339 154,465
Other 58,569 4,984 2,105 65,658
------------- ------------- ------------- -------------
Total revenues 2,226,140 308,521 249,442 2,784,103
------------- ------------- ------------- -------------
COSTS AND EXPENSES
Lease operating expenses 319,154 52,340 69,286 440,780
Transportation costs 41,956 11,353 -- 53,309
Production taxes 101,739 1,080 425 103,244
Depreciation, depletion and amortization of
property and equipment 565,633 64,735 62,972 693,340
Amortization of goodwill 41,303 -- 29 41,332
General and administrative expenses 80,358 10,380 2,270 93,008
Expenses related to mergers 60,373 -- -- 60,373
Interest expense 143,169 10,140 1,020 154,329
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt -- 2,408 -- 2,408
------------- ------------- ------------- -------------
Total costs and expenses 1,353,685 152,436 136,002 1,642,123
------------- ------------- ------------- -------------
Earnings before income tax expense 872,455 156,085 113,440 1,141,980
INCOME TAX EXPENSE
Current 112,757 2,268 15,768 130,793
Deferred 185,231 67,318 28,296 280,845
------------- ------------- ------------- -------------
Total income tax expense 297,988 69,586 44,064 411,638
------------- ------------- ------------- -------------
Net earnings $ 574,467 86,499 69,376 730,342
============= ============= ============= =============
Capital expenditures $ 893,087 202,673 184,372 1,280,132
============= ============= ============= =============
80
17. SEGMENT INFORMATION (CONTINUED)
U.S. CANADA INTERNATIONAL TOTAL
------------- ------------- ------------- -------------
(IN THOUSANDS)
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 $ 332,219 80,298 148,501 561,018
Gas sales 501,841 114,128 11,900 627,869
Natural gas liquids sales 57,610 10,075 300 67,985
Other 14,574 4,652 1,370 20,596
------------- ------------- ------------- -------------
Total revenues 906,244 209,153 162,071 1,277,468
------------- ------------- ------------- -------------
COSTS AND EXPENSES
Lease operating expenses 188,576 49,831 60,400 298,807
Transportation costs 22,524 11,401 -- 33,925
Production taxes 42,977 1,363 400 44,740
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 1,219,345 151,751 105,750 1,476,846
------------- ------------- ------------- -------------
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
============= ============= ============= =============
81
17. SEGMENT INFORMATION (CONTINUED)
U.S. CANADA INTERNATIONAL TOTAL
------------- ------------- ------------- -------------
(IN THOUSANDS)
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 $ 152,297 75,493 82,200 309,990
Gas sales 245,145 89,828 12,300 347,273
Natural gas liquids sales 19,871 4,644 200 24,715
Other 9,294 13,754 1,200 24,248
------------- ------------- ------------- -------------
Total revenues 426,607 183,719 95,900 706,226
------------- ------------- ------------- -------------
COSTS AND EXPENSES
Lease operating expenses 127,451 47,910 51,200 226,561
Transportation costs 14,251 8,935 -- 23,186
Production taxes 22,910 1,661 300 24,871
Depreciation, depletion and amortization 165,654 44,590 32,900 243,144
of property and equipment
General and administrative expenses 35,752 12,502 (2,800) 45,454
Expenses related to mergers 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
subsidiary trust 9,717 -- -- 9,717
Reduction of carrying value of oil and
gas properties 301,400 -- 121,100 422,500
------------- ------------- ------------- -------------
Total costs and expenses 700,757 163,761 203,700 1,068,218
------------- ------------- ------------- -------------
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
============= ============= ============= =============
82
18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Following is a summary of the unaudited interim results of operations
for the years ended December 31, 2000 and 1999.
2000
----------------------------------------------------------------------------
FIRST SECOND THIRD FOURTH FULL
QUARTER QUARTER QUARTER QUARTER YEAR
------------ ------------ ------------ ------------ ------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Oil, gas and natural gas liquids sales $ 548,351 635,777 695,475 838,842 2,718,445
Total revenues $ 560,416 648,484 725,141 850,062 2,784,103
Net earnings (loss) $ 105,187 153,334 164,912 306,909 730,342
Net earnings (loss) per common share:
Basic $ 0.81 1.19 1.27 2.37 5.66
Diluted $ 0.80 1.17 1.22 2.27 5.50
1999
-----------------------------------------------------------------------------
FIRST SECOND THIRD FOURTH FULL
QUARTER QUARTER QUARTER QUARTER YEAR
------------ ------------ ------------ ------------ ------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Oil, gas and natural gas liquids sales $ 159,632 221,129 380,562 495,549 1,256,872
Total revenues $ 162,205 224,048 385,972 505,243 1,277,468
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)
The third and fourth quarters of 2000 include $57.2 million and $3.2
million, respectively, of expenses incurred in connection with the Santa Fe
Snyder merger. The after-tax effect of these expenses was $35.3 million and $1.9
million, respectively. The per share effect of these quarterly reductions was
$0.28 and $0.01, respectively.
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.
83
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial
Statements and Consolidated Financial Statement
Schedules appearing at Item 8 on Page 29 of this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they
are inapplicable, or the required information has been
included in the consolidated financial statements or
notes thereto.
3. Exhibits
23.5 Consent of KPMG LLP.
23.6 Consent of PricewaterhouseCoopers LLP
23.7 Consent of Deloitte & Touche LLP
(b) Reports on Form 8-K -- A Current Report on Form 8-K dated
December 12, 2000, was filed by the Registrant regarding year
2001 forward looking estimates. A Current Report on Form 8-K
dated January 29, 2001, was filed by the Registrant regarding
year-end 2000 oil and gas reserves and fixed prices of future
oil and gas production.
84
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
DEVON ENERGY CORPORATION
December 18, 2001 By /s/ DANNY J. HEATLY
------------------------------------------
Danny J. Heatly
Vice President -- Accounting
85
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
23.5 Consent of KPMG LLP
23.6 Consent of PricewaterhouseCoopers LLP
23.7 Consent of Deloitte & Touche LLP