UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event report): December 11, 2001
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
DELAWARE 000-30176 73-1567067
(State or Other Jurisdiction of (Commission File Number) (IRS Employer
Incorporation or Organization) Identification Number)
20 NORTH BROADWAY, SUITE 1500, OKLAHOMA CITY, OK 73102
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (405) 235-3611
Page 1 of 14 pages
ITEM 5. OTHER EVENTS
DEFINITIONS
The following discussion includes references to various abbreviations
relating to volumetric production terms and other defined terms. These
definitions are as follows:
"AECO" means Alberta Energy Company.
"Bbl" or "Bbls" means barrel or barrels.
"Bcf" means billion cubic feet.
"Boe" means barrel of oil equivalent, determined by using the
ratio of one Bbl of oil or NGLs to six Mcf of gas.
"Btu" means British thermal units, a measure of heating value.
"Inside FERC" refers to the publication Inside F.E.R.C.'s Gas
Market Report.
"LIBOR" means London Interbank Offered Rate.
"MMBbls" means one million Bbls.
"MMBoe" means one million Boe.
"MMBtu" means one million Btu.
"Mcf" means one thousand cubic feet.
"NGL" or "NGLs" means natural gas liquids.
"NYMEX" means New York Mercantile Exchange.
"Oil" includes crude oil and condensate.
FORWARD-LOOKING ESTIMATES
The forward-looking statements provided in this discussion are based on
management's examination of historical operating trends, the information which
will be used to prepare the December 31, 2001 reserve reports of independent
petroleum engineers and other data in Devon Energy Corporation's ("Devon's")
possession or available from third parties. Also, the pending acquisition of
Mitchell Energy & Development Corp. ("Mitchell") is assumed to close on January
31, 2002 and is included in the following estimates for the last eleven months
of the year. The acquisition of Mitchell is subject to approval by the
shareholders of both Devon and Mitchell as well as other terms and conditions of
the merger agreement. Should the acquisition fail to be completed, or should it
close on a date other than January 31, 2002, the estimates set forth herein
could be rendered obsolete. 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 or 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
2
below. Additionally, Devon cautions that its future gas services revenues and
expenses are subject to all of the risks and uncertainties normally incident to
the gas services business. These risks include, but are not limited to, price
volatility, environmental risks, regulatory changes, the uncertainty inherent in
estimating future processing volumes and pipeline throughput, 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 NGLs 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 vary considerably due to differences between regional markets,
transportation availability and demand for different grades of oil, gas and
NGLs. Substantially all of Devon's revenues are attributable to sales of these
three commodities. Consequently, Devon's financial results and resources are
highly influenced by price volatility.
Estimates for Devon's future production of oil, natural gas and NGLs
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 NGLs 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.
Estimates for Devon's future processing and transport of natural gas
and NGLs are based on the assumption that market demand and prices for gas and
NGLs will continue at levels that allow for profitable processing and transport
of these products. There can be no assurance of such stability.
The production, transportation, processing and marketing of oil,
natural gas and NGLs 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 NGLs during 2002 will be substantially similar to those of
2001, unless otherwise noted. Given the general limitations expressed herein,
Devon's forward-looking statements for 2002 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 $0.65 U.S. dollar to $1.00 Canadian
dollar. The actual 2002 exchange rate may vary materially from this estimated
rate. Such variations could have a material effect on the following Canadian
estimates.
The following forward-looking data excludes the financial and operating
effects of potential property acquisitions or divestitures, except for the
Mitchell acquisition and except as discussed in "Property Acquisitions and
Divestitures", during the year 2002.
3
The timing and ultimate results of such acquisition and divestiture activity is
difficult to predict, and may vary materially from that discussed in this
report.
GEOGRAPHIC REPORTING AREAS FOR 2002 The following estimates of
production, average price differentials and capital expenditures are provided
separately for each of Devon's geographic reporting areas. These areas are as
follows:
o the United States;
o Canada; and
o International, which encompasses all oil and gas properties that lie outside
of the United States and Canada.
YEAR 2002 POTENTIAL OPERATING ITEMS
The estimates related to oil, gas and NGL production, operating costs
and DD&A set forth in the following paragraphs are based on estimates for
Devon's properties other than those that have been designated for possible sale
(See "Property Acquisitions and Divestitures"). Therefore, the following
estimates exclude the results of the potential sale properties for the entire
year. Also, all of the estimates assume that the Mitchell acquisition closes on
January 31, 2002.
OIL, GAS AND NGL PRODUCTION Set forth in the following paragraphs are
individual estimates of Devon's oil, gas and NGL production for 2002. On a
combined basis, Devon estimates its 2002 oil, gas and NGL production will total
between 175.4 and 186.4 MMBoe. Of this total, approximately 92% is estimated to
be produced from reserves expected to be classified as "proved" at December 31,
2001.
OIL PRODUCTION Devon expects its oil production in 2002 to total
between 34.5 and 36.7 MMBbls. Of this total, approximately 95% is estimated to
be produced from reserves expected to be classified as "proved" at December 31,
2001. The expected ranges of production by area are as follows:
(MMBbls)
--------
United States 18.3 to 19.5
Canada 14.4 to 15.3
International 1.8 to 1.9
OIL PRICES - FIXED Devon has fixed the price it will receive in 2002 on
a portion of its oil production through certain forward oil sales. Devon has
executed forward oil sales attributable to the United States for 2.5 MMBbls at
an average price of $16.84 per Bbl. It should be noted that these forward sales
apply only to the first eight months of 2002.
4
For 2002, Devon has executed price swaps attributable to the United
States for 8.0 MMBbls at an average price of $23.85 per Bbl. Additionally, for
2002, Devon has entered into price swaps attributable to Canada for 1.6 MMBbls
at an average price of $20.33 per Bbl.
OIL PRICES - FLOATING For oil production for which prices have not been
fixed, Devon's 2002 average prices for each of its areas are expected to differ
from the NYMEX price as set forth in the following table.
EXPECTED RANGE OF OIL PRICES
LESS THAN NYMEX PRICE
----------------------------
United States ($2.35) to ($1.35)
Canada ($6.05) to ($4.05)
International ($4.05) to ($3.05)
Devon has also entered into costless price collars that set a floor
price and a ceiling price for 7.3 MMBbls of United States 2002 oil production
that otherwise is subject to floating prices. The collars have a floor and
ceiling price per Bbl of $23.00 and $28.19, respectively. The floor and ceiling
prices related to domestic oil production are based on the NYMEX price. The
NYMEX price is the monthly average of settled prices on each trading day for
West Texas Intermediate Crude oil delivered at Cushing, Oklahoma. If the NYMEX
price is outside of the ranges set by the floor and ceiling prices in the
various collars, Devon and the counterparty to the collars will settle the
difference. Any such settlements will either increase or decrease Devon's oil
revenues for the period. Because Devon's oil volumes are often sold at prices
that differ from the NYMEX price due to differing quality (i.e., sweet crude
versus sour crude) and transportation costs from different geographic areas, the
floor and ceiling prices of the various collars do not reflect actual limits of
Devon's realized prices for the production volumes related to the collars.
GAS PRODUCTION Devon expects its 2002 gas production to total between
747 Bcf and 793 Bcf. Of this total, approximately 90% is estimated to be
produced from reserves expected to be classified as "proved" at December 31,
2001. The expected ranges of production by area are as follows:
(Bcf)
-----
United States 473 to 502
Canada 274 to 291
GAS PRICES - FIXED Through various price swaps and fixed-price physical
delivery contracts, Devon has fixed the price it will receive in 2002 on a
portion of its natural gas production. The following tables include information
on this fixed-price production by area. Where necessary, the prices have been
adjusted for certain transportation costs that are netted against the prices
recorded by Devon, and the prices have also been adjusted for the Btu content of
the gas hedged.
5
FIRST HALF OF 2002 SECOND HALF OF 2002
------------------ -------------------
Mcf/DAY PRICE/Mcf Mcf/DAY PRICE/Mcf
------- --------- ------- ---------
United States 217,352 $ 3.03 219,008 $ 3.03
Canada 107,913 $ 1.88 95,613 $ 1.92
GAS PRICES - FLOATING For the natural gas production for which prices
have not been fixed, Devon's 2002 average prices for each of its areas are
expected to differ from the NYMEX price as set forth in the following table. The
NYMEX price is determined to be the first-of-month South Louisiana Henry Hub
price index as published monthly in Inside FERC.
EXPECTED RANGE OF GAS PRICES
GREATER THAN (LESS THAN) NYMEX PRICE
------------------------------------
United States ($0.45) to $0.05
Canada ($0.75) to ($0.25)
Devon has also entered into costless price collars that set a floor and
ceiling price for a portion of its 2002 natural gas production that otherwise is
subject to floating prices. If the applicable monthly price indices are outside
of the ranges set by the floor and ceiling prices in the various collars, Devon
and the counterparty to the collars 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
the related regional indices, and due to differing Btu contents of gas produced,
the floor and ceiling prices of the various collars do not reflect actual limits
of Devon's realized prices for the production volumes related to the collars.
Devon has entered into numerous costless collars concerning its 2002
gas production. To simplify presentation, these collars have been aggregated in
the following table according to similar floor prices. The floor and ceiling
prices shown are weighted averages of the various collars in each aggregated
group.
The prices shown in the following table have been adjusted to a
NYMEX-based price, using Devon's estimates of 2002 differentials between NYMEX
and the specific regional indices upon which the collars are based. The floor
and ceiling prices related to the domestic collars are based on various regional
first-of-the-month price indices as published monthly by Inside FERC. The floor
and ceiling prices related to the Canadian collars are based on the AECO index
as published by the Canadian Gas Price Reporter.
6
FIRST HALF OF 2002 SECOND HALF OF 2002
------------------------------------- -------------------------------------
FLOOR CEILING FLOOR CEILING
PRICE PRICE PRICE PRICE
PER PER PER PER
AREA (RANGE OF FLOOR PRICES) MMBtu/DAY MMBtu MMBtu MMBtu/DAY MMBtu MMBtu
---------------------------- --------- ----- ----- --------- ----- -----
United States ($3.35 - $3.65) 285,000 $ 3.52 $ 7.37 285,000 $ 3.52 $ 7.37
United States ($2.96 - $3.11) 130,000 $ 3.01 $ 4.53 --- $ -- $ --
United States ($2.75 - $2.79) 35,000 $ 2.76 $ 3.72 35,000 $ 2.76 $ 3.72
Canada ($3.54 - $3.72) 23,705 $ 3.64 $ 6.82 23,705 $ 3.64 $ 6.82
Canada ($3.19 - $3.32) 9,481 $ 3.26 $ 4.50 --- $ -- $ --
Canada ($2.72 - $2.99) 34,481 $ 2.79 $ 3.88 25,000 $ 2.72 $ 3.67
NGL PRODUCTION Devon expects its 2002 production of NGLs to total
between 16.4 million barrels and 17.5 million barrels. Of this total, 98% is
estimated to be produced from reserves expected to be classified as "proved" at
December 31, 2001. The expected ranges of production by area are as follows:
(MMBbls)
--------
United States 11.9 to 12.7
Canada 4.5 to 4.8
GAS SERVICES REVENUES AND EXPENSES Devon's gas services revenues and
expenses are derived from its natural gas processing plants and natural gas
transport pipelines. These revenues and expenses vary in response to several
factors. The factors include, but are not limited to, changes in production from
wells connected to the pipelines and related processing plants, changes in the
relative prices of natural gas and NGLs, provisions of the contract agreements
and the amount of repair and workover activity required to maintain anticipated
processing levels.
These factors, coupled with uncertainty of future natural gas and NGL
prices, increase the uncertainty inherent in estimating future gas services
revenues and expenses. Given these uncertainties, Devon estimates that 2002 gas
services revenues will be between $917 million and $974 million and gas services
expenses will be between $709 million and $752 million.
OTHER REVENUES Devon's other revenues in 2002 are expected to be
between $14 million and $18 million.
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
7
gas and NGL prices also have an effect on lease operating expense and impact the
economic feasibility of planned workover projects.
Given these uncertainties, Devon estimates that year 2002 lease
operating expenses will be between $540 million and $574 million, transportation
costs will be between $153 million and $163 million and production taxes will be
between 3.9% and 4.4% of consolidated oil, natural gas and NGL revenues.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") The 2002 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 2002 compared to the costs incurred for such efforts, and
the revisions to Devon's year-end 2001 reserve estimates that, based on prior
experience, are likely to be made during 2002.
Oil and gas property related DD&A expense for 2002 is expected to be
between $1.1 billion and $1.3 billion. Additionally, Devon expects its 2002 DD&A
expense related to non-oil and gas property fixed assets to total between $88
million and $93 million. This range includes $54 million to $57 million related
to gas services assets. Based on these DD&A amounts and the production estimates
discussed earlier, Devon expects its consolidated DD&A rate will be between
$6.96 per Boe and $7.39 per Boe.
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 2002 is expected to be between $174 million and $184
million.
INTEREST EXPENSE Future interest rates and oil, natural gas and NGL
prices have a significant effect on Devon's interest expense. Devon can only
marginally influence the prices it will receive in 2002 from sales of oil,
natural gas and NGLs and the resulting cash flow. The proceeds and the timing of
the potential property sales in 2002 will also affect interest expense. Such
proceeds could be used to retire either fixed-rate debt or variable-rate debt.
At this time, the amount of proceeds and the timing of such property sales, as
well as the application of the proceeds, are not possible to accurately predict.
(See "Property Acquisitions and Divestitures.") 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.
Assuming no changes in debt balances during 2002 other than the
assumption of certain debt from Mitchell, Devon's average balance of fixed rate
debt during 2002 will be $5.7 billion. The interest expense in 2002 related to
this fixed-rate debt will be
8
approximately $407 million. This fixed-rate debt removes the uncertainty of
future interest rates from some, but not all, of Devon's long-term debt. Devon's
floating rate debt is discussed in the following paragraphs.
After completion of the Mitchell acquisition, Devon expects to have
100% of its $3.0 billion senior unsecured term loan credit facility borrowed.
Interest on borrowings under this facility may be based, at the borrower's
option, on LIBOR, plus a margin determined by Devon's long-term senior unsecured
debt ratings. Regardless of the current debt ratings, the margin for borrowings
based on LIBOR will be 1.0% until at least June 30, 2002. As of November 30,
2001, the one week LIBOR was 2.1%. Effective December 12, 2001, Devon may begin
borrowing with interest periods of up to six months under the term loan credit
facility.
From time to time, Devon borrows under its $1 billion credit
facilities. Borrowings under the U.S. facility, currently set at $725 million,
may be borrowed at various rate options including LIBOR plus a margin with
interest periods of up to 6 months. Borrowings under the Canadian facility,
currently set at $275 million, may be borrowed at various rate options including
LIBOR plus a margin with interest periods up to six months, or Bankers
Acceptances plus a margin with interest periods of 30 to 180 days. The current
LIBOR margin ranges from 35.0 to 37.5 basis points and the current Bankers
Acceptance margin is 35.0 basis points. The total borrowed under these
facilities was $0.1 billion at September 30, 2001, at an average interest rate
of 3.9%.
From time to time, Devon also borrows under its $725 million commercial
paper facility. The total borrowed under this program was $0.1 billion at
September 30, 2001, at an average interest rate of 3.2%. Debt outstanding under
this program is generally borrowed for 7 to 90 day periods, and may be borrowed
up to 365 days, at prevailing commercial paper market rates.
Devon has fixed the interest rate on $132.5 million Canadian dollars
and $50.0 million U.S. dollars of its floating rate debt through swap agreements
at average rates of 6.75% and 6.91%, respectively. The Canadian dollar swap
agreements mature at various dates through July 2007 and the U.S. dollar swap
agreement matures in May 2003.
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES Devon follows the
full cost method of accounting for its oil and gas properties. Under the full
cost method, Devon's net book value of oil and gas properties, less related
deferred income taxes (the "costs to be recovered"), may not exceed a calculated
"full cost ceiling." The ceiling limitation is the discounted estimated
after-tax future net revenues from 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 costs to be
recovered are compared to the ceiling on a quarterly basis. If the costs to be
recovered exceed the ceiling, the excess 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.
9
Because of the volatile nature of oil and gas prices, it is not
possible to predict whether Devon will incur a full cost writedown in future
periods. However, prices for oil and gas as of the date of this report, and the
impact of the October 2001 acquisition of Anderson Exploration Ltd. ("Anderson")
and the pending Mitchell acquisition, increase the likelihood that Devon will
incur a full cost writedown as of the end of 2001 and/or in subsequent periods,
including 2002.
DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY RATE ON SUBSIDIARIES'
LONG-TERM DEBT Anderson, which Devon acquired in October 2001, has $460 million
of long-term debt which is denominated in U.S. dollars. Of this debt, $400
million matures in 2011. The remaining $60 million of debt matures at various
dates from 2002 through 2006. Changes in the exchange rate between the U.S.
dollar and the Canadian dollar from October 15, when Devon acquired Anderson, to
the dates of repayment will increase or decrease the expected amount of Canadian
dollars eventually required to repay the debt. Such changes in the Canadian
dollar equivalent balance of the debt are required to be included in determining
net earnings for the period in which the exchange rate changes. Because of the
variability of the exchange rate, it is not possible to estimate the deferred
effect which will be recorded in 2002. However, for every $0.01 change in the
exchange rate, Devon will record a deferred effect (either revenue or expense)
of approximately $11 million Canadian dollars. The resulting revenue or expense
in U.S. dollars will depend on the currency exchange rate in effect throughout
the year.
INCOME TAXES Devon's financial income tax rate in 2002 will vary
materially depending on the actual amount of financial pre-tax earnings. There
are certain tax deductions and credits that will have a fixed impact on 2002's
income tax expense regardless of the level of pre-tax earnings that are
produced. Due to the significance of these deductions and credits as compared to
possible pre-tax earnings, it is not possible to estimate an accurate single
range of financial income tax rates that will apply to all the possible levels
of pre-tax earnings that might be generated during 2002. Therefore, the
following estimates are provided based on various ranges of financial pre-tax
earnings for 2002.
INCOME TAX EXPENSE (BENEFIT) RATE
PRE-TAX EARNINGS CURRENT DEFERRED TOTAL
---------------- ------- -------- -----
$100 - $225 million 65% to 40% (130%) to (50%) (65%) to (10%)
$226 - $450 million 40% to 35% (50%) to (20%) (10%) to 15%
$451 - $675 million 35% to 30% (20%) to (10%) 15% to 20%
It is uncertain whether Devon's pre-tax earnings will fall into the
ranges presented within the table above. Among the factors which could cause
Devon's pre-tax earnings to fall outside these ranges is price volatility. In
addition to price volatility's effect on revenues, such volatility could also
cause Devon to incur a full cost reduction of oil and gas properties. Variances
in revenues or expenses resulting from price volatility could cause Devon's
pre-tax earnings to fall outside the ranges presented.
10
PROPERTY ACQUISITIONS AND DIVESTITURES 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, other than
the Mitchell acquisition which in this report is assumed to close on January 31,
2002.
During 2002, Devon contemplates the disposition of certain oil and gas
properties (the "Disposition Properties"). The Disposition Properties are
predominantly properties that are either outside of Devon's core-operating areas
or otherwise do not fit Devon's current strategic objectives. The Disposition
Properties are located in the U.S., Canada and International areas. At this
time, Devon is in the early stages of the disposition process, and it is
impossible to identify when, or if, the dispositions will occur.
The estimates of Devon's 2002 results previously set forth exclude any
results from the Disposition Properties. The Disposition Properties' actual
contributions to Devon's 2002 operating results will depend upon the timing of
the dispositions. The estimated full-year 2002 results from the Disposition
Properties (which are not included in the previous 2002 estimates included in
this report) are as follows:
EXPECTED RANGE OF PRODUCTION
OIL GAS NGL TOTAL
(MMBbls) (Bcf) (MMBbls) MMBoe
-------- ----- -------- -----
United States 6.8 to 7.2 45 to 48 0.6 to 0.7 14.9 to 15.9
Canada 2.9 to 3.1 13 to 14 0.3 to 0.4 5.4 to 5.8
International 7.1 to 7.5 10 to 11 0.1 to 0.2 8.9 to 9.5
Total 16.8 to 17.8 68 to 73 1.0 to 1.3 29.2 to 31.2
EXPECTED RANGE OF EXPENSE
($ IN MILLIONS)
-------------------------
Lease operating expenses $178 to $189
Transportation costs $ 10 to $ 11
DD&A expenses $195 to $207
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, other than the Mitchell acquisition which in
this report is assumed to close on January 31, 2002.
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 actual prices received differ materially from Devon's
price expectations for its future production, some projects may be accelerated
or deferred and, consequently, may increase or decrease total 2002 capital
expenditures. In addition, if the actual costs of the
11
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 2002 capital
expenditures for drilling and development efforts, plus related facilities, to
total between $1.2 billion and $1.4 billion. These amounts include between $495
million and $595 million for drilling and facilities costs related to reserves
expected to be classified as proved as of year-end 2001. In addition, these
amounts include between $365 million and $435 million for other low risk/reward
projects and between $300 million and $350 million for new, higher risk/reward
projects. Low risk/reward projects include development drilling that does not
offset currently productive units and for which there is not a certainty of
continued production from a known productive formation. Higher risk/reward
projects include exploratory drilling to find and produce oil or gas in
previously untested fault blocks or new reservoirs.
The following table shows expected drilling and facilities expenditures
by geographic area.
DRILLING AND PRODUCTION FACILITIES EXPENDITURES
United States Canada International Total
------------- ---------- ------------- -------------
($ in millions)
Related to Proved Reserves $435-$495 $ 15-$ 35 $45-$ 65 $ 495-$ 595
Lower Risk/Reward Projects $170-$200 $195-$225 $ 0-$ 10 $ 365-$ 435
Higher Risk/Reward Projects $ 70-$ 80 $210-$240 $20-$ 30 $ 300-$ 350
--------- --------- -------- -------------
Total $675-$775 $420-$500 $65-$105 $1,160-$1,380
========= ========= ======== =============
In addition to the above expenditures for drilling and development,
Devon expects to spend between $135 million to $165 million on its gas services
assets, which include its gas processing plants and gas transport pipelines.
Devon also expects to capitalize between $85 million and $105 million of G&A
expenses in accordance with the full cost method of accounting. Devon also
expects to pay between $20 million and $30 million for plugging and abandonment
charges, and to spend between $15 million and $25 million for non-oil and gas
property fixed assets.
The above capital expenditure estimates do not include the cost to
acquire Mitchell in 2002. Devon will pay $31 per share in cash to acquire the
Mitchell shares outstanding at closing. At closing, this will result in Devon
paying approximately $1.6 billion to the Mitchell stockholders. Devon will also
issue 0.585 shares of Devon common stock for each share of Mitchell common stock
at closing. For accounting purposes, the Devon shares will be valued at $50.95
per share, which was the value at the time the Mitchell acquisition was
announced in August 2001. This is expected to result in the shares of Devon
common stock to be issued at closing to be valued at approximately $1.5 billion.
12
The actual allocation of the Mitchell acquisition cost to the various
assets and liabilities will not be final until sometime following the close in
January 2002. However, on a pro forma basis assuming the acquisition had closed
on September 30, 2001, the amount of the acquisition cost allocated to fixed
assets was as follows:
Proved oil and gas properties $1.5 billion
Unproved oil and gas properties $0.7 billion
Gas services facilities and equipment $0.8 billion
----
$3.0 billion
====
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 155 million shares of common stock expected to be
outstanding after completion of the Mitchell acquisition, 2002 dividends are
expected to approximate $31 million. Also, Devon has $150 million of 6.49%
cumulative preferred stock upon which it will pay $9.7 million of dividends in
2002.
CAPITAL RESOURCES AND LIQUIDITY Devon's estimated 2002 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 2002 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 2002. As of
November 30, 2001, Devon had $0.9 billion 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.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned hereto duly authorized.
DEVON ENERGY CORPORATION
By: /s/ Danny J. Heatly
----------------------------------
Danny J. Heatly
Vice President - Accounting
Date: December 11, 2001
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