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 10, 2002
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, 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 the price of gas delivered onto the NOVA Gas
Transmission Ltd. system.
"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, 2002 reserve reports of independent
petroleum engineers and other data in Devon Energy Corporation's ("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, production and sale of oil, gas and NGLs. 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 below. Additionally, Devon cautions that its future
marketing and midstream revenues and expenses are subject to all of the risks
and uncertainties normally incident to the marketing and midstream 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.
2
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 worldwide economic conditions, weather and other
local market conditions. 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 costs and demand for the various products
derived from oil, natural gas and NGLs. Substantially all of Devon's revenues
are attributable to sales, processing and transportation 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, gas and NGLs
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 2003 will be substantially similar to those of
2002, unless otherwise noted.
Given the general limitations expressed herein, following are Devon's
forward-looking statements for 2003. Unless otherwise noted, all of the
following dollar amounts are expressed in U.S. dollars. 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 2003 exchange rate may
vary materially from this estimated rate. Such variations could have a material
effect on the following estimates.
Though Devon has completed several major property acquisitions and
dispositions 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 or dispositions, if any.
3
GEOGRAPHIC REPORTING AREAS FOR 2003 The following estimates of
production, average price differentials and capital expenditures are provided
separately for each of the following geographic areas:
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 2003 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 for 2003. On a
combined basis, Devon estimates its 2003 oil, gas and NGL production will total
between 178.1 and 186.9 MMBoe. Of this total, approximately 92% is estimated to
be produced from reserves expected to be classified as "proved" at December 31,
2002.
OIL PRODUCTION Devon expects its oil production in 2003 to total
between 35.4 and 37.2 MMBbls. Of this total, approximately 92% is estimated to
be produced from reserves expected to be classified as "proved" at December 31,
2002. The expected ranges of production by area are as follows:
(MMBbls)
--------
United States 19.1 to 20.1
Canada 13.5 to 14.2
International 2.8 to 2.9
OIL PRICES - FLOATING Devon's 2003 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 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
LESS THAN NYMEX PRICE
----------------------------
United States $(3.00) to $(2.00)
Canada $(6.25) to $(4.25)
International $(2.80) to $(1.80)
Devon has also entered into costless price collars that set a floor and
ceiling price for a portion of its 2003 oil production that otherwise is subject
to floating prices. The floor and ceiling prices related to domestic and
Canadian oil production are based on the NYMEX price. 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
4
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.
To simplify presentation, Devon's costless collars have been aggregated
in the following table according to similar floor prices and similar ceiling
prices. The floor and ceiling prices shown are weighted averages of the various
collars in each aggregated group.
WEIGHTED AVERAGE
-----------------------------
FLOOR CEILING
PRICE PRICE
AREA (RANGE OF FLOOR PRICES/CEILING PRICES) Bbls/DAY PER Bbl PER Bbl
------------------------------------------- ------------ ------------ ------------
United States ($20.00 - $20.00/$28.40 - $28.65) 5,000 $ 20.00 $ 28.55
United States ($22.00 - $22.00/$27.05 - $28.00) 8,000 $ 22.00 $ 27.45
United States ($22.75 - $22.75/$27.75 - $28.40) 5,000 $ 22.75 $ 27.99
United States ($23.25 - $23.50/$28.25 - $29.75) 6,000 $ 23.33 $ 29.03
Canada ($20.00 - $21.00/$26.60 - $28.15) 5,000 $ 20.40 $ 27.37
Canada ($22.00 - $22.00/$27.00 - $27.50) 8,000 $ 22.00 $ 27.24
Canada ($22.75 - $22.75/$27.75 - $28.40) 5,000 $ 22.75 $ 27.97
Canada ($23.25 - $23.25/$28.35 - $29.25) 4,000 $ 23.25 $ 28.79
GAS PRODUCTION Devon expects its 2003 gas production to total between
731 Bcf and 767 Bcf. Of this total, approximately 91% is estimated to be
produced from reserves expected to be classified as "proved" at December 31,
2002. The expected ranges of production by area are as follows:
(Bcf)
----------
United States 472 to 495
Canada 259 to 272
GAS PRICES - FIXED Through various price swaps and fixed-price physical
delivery contracts, Devon has fixed the price it will receive in 2003 on a
portion of its natural gas production. The following table includes 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.
FIRST HALF OF 2003 SECOND HALF OF 2003
-------------------------------- --------------------------------
Mcf/DAY PRICE/Mcf Mcf/DAY PRICE/Mcf
------------ ------------ ------------ ------------
United States 97,148 $ 3.23 97,148 $ 3.23
Canada 44,016 $ 2.32 43,441 $ 2.34
GAS PRICES - FLOATING For the natural gas production for which prices
have not been fixed, Devon's 2003 average prices for each of its areas are
expected to differ from
5
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
LESS THAN NYMEX PRICE
----------------------------
United States $(0.80) to $(0.30)
Canada $(0.90) to $(0.40)
Devon has also entered into costless price collars that set a floor and
ceiling price for a portion of its 2003 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.
To simplify presentation, Devon's costless collars have been aggregated
in the following table according to similar floor prices and similar ceiling
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 2003 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.
WEIGHTED AVERAGE
--------------------------------
FLOOR CEILING
PRICE PER PRICE PER
AREA (RANGE OF FLOOR PRICES/CEILING PRICES) MMBtu/DAY MMBtu MMBtu
------------------------------------------- ------------ ------------ ------------
United States ($3.24 - $3.40/$4.02 - $4.40) 130,000 $ 3.32 $ 4.23
United States ($3.25 - $3.25/$5.50 - $6.50) 85,000 $ 3.25 $ 5.99
United States ($3.25 - $3.25/$4.65 - $4.90) 70,000 $ 3.25 $ 4.78
United States ($3.00 - $3.19/$4.02 - $4.40) 110,000 $ 3.06 $ 4.17
Canada ($3.45 - $3.49/$5.22 - $6.46) 50,018 $ 3.48 $ 5.73
Canada ($3.40 - $3.47/$4.22 - $4.84) 90,004 $ 3.43 $ 4.29
6
NGL PRODUCTION Devon expects its 2003 production of NGLs to total
between 20.9 MMBbls and 21.9 MMBbls. Of this total, 96% is estimated to be
produced from reserves expected to be classified as "proved" at December 31,
2002. The expected ranges of production by area are as follows:
(MMBbls)
------------
United States 16.6 to 17.4
Canada 4.3 to 4.5
MARKETING AND MIDSTREAM REVENUES AND EXPENSES Devon's marketing and
midstream revenues and expenses are derived primarily 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 absolute and 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 marketing and
midstream revenues and expenses. Given these uncertainties, Devon estimates that
2003 marketing and midstream revenues will be between $971 million and $1,031
million and marketing and midstream expenses will be between $784 million and
$833 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 gas and NGL prices
also have an effect on lease operating expenses and impact the economic
feasibility of planned workover projects.
Given these uncertainties, Devon estimates that 2003 lease operating
expenses will be between $621 million and $659 million, transportation costs
will be between $141 million and $150 million, and production taxes will be
between 3.7% and 4.2% of consolidated oil, natural gas and NGL revenues,
excluding revenues related to hedges upon which production taxes are not
incurred.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") The 2003 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 2003 compared to the costs incurred for such efforts, and
the revisions to Devon's year-end 2002 reserve estimates that, based on prior
experience, are likely to be made during 2003.
7
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligation ("SFAS No. 143"). Devon will be required to adopt SFAS No.
143 effective January 1, 2003 using a cumulative effect approach to recognize
transition amounts for asset retirement obligations, asset retirement costs and
accumulated depreciation. SFAS No. 143 requires liability recognition for
retirement obligations associated with tangible long-lived assets, such as
producing well sites, offshore production platforms, and natural gas processing
plants. The obligations included within the scope of SFAS No. 143 are those for
which a company faces a legal obligation for settlement. The initial measurement
of the asset retirement obligation is to be fair value, defined as "the price
that an entity would have to pay a willing third party of comparable credit
standing to assume the liability in a current transaction other than in a forced
or liquidation sale." Devon expects that it will use a valuation technique such
as present value of expected cash outflows to estimate fair value. The adoption
will result in accretion expense related to this fair value as a result of the
passage of time.
The asset retirement cost equal to the fair value of the retirement
obligation is to be capitalized as part of the cost of the related long-lived
asset and allocated to expense using a systematic and rational method.
Devon currently records estimated costs of dismantlement, removal, site
reclamation, and other similar activities as part of depreciation, depletion,
and amortization and does not record a separate liability for such amounts.
Devon has not completed the assessment of the impact that adoption of SFAS No.
143 will have on its consolidated financial statements, and therefore cannot
accurately estimate at this time the amount of accretion expense expected to be
recognized in 2003. Devon also cannot accurately estimate at this time the
effect which adopting SFAS No. 143 will have on DD&A expense in 2003.
Based on these uncertainties, oil and gas property related DD&A expense
for 2003 is expected to be between $1.1 billion and $1.2 billion before the
effect of adopting SFAS No. 143. Additionally, Devon expects its DD&A expense
related to non-oil and gas property fixed assets to total between $124 million
and $132 million. This range includes $78 million to $83 million related to
marketing and midstream assets. Based on these DD&A amounts and the production
estimates set forth earlier, Devon expects its consolidated DD&A rate will be
between $6.77 per Boe and $7.11 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 2003 is expected to be between $222 million and $237
million.
8
INTEREST EXPENSE Future interest rates, debt outstanding 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 2003
from sales of oil, natural gas and NGLs 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.
Assuming no changes in fixed-rate debt balances during 2003, Devon's
average balance of fixed rate debt during 2003 will be $6.5 billion. The
interest expense in 2003 related to this fixed-rate debt, including net
accretion of related discounts, will be approximately $472 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.
As of November 30, 2002, Devon had $1.1 billion outstanding under its
original $3.0 billion amortizing senior unsecured term loan credit facility.
This credit facility, which was entered into in October 2001, has a term of five
years. This credit facility is non-revolving.
The remaining balance outstanding as of November 30, 2002 will mature
as follows:
(In Millions)
---------------
April 15, 2006 $ 335
October 15, 2006 800
---------------
$ 1,135
===============
This $3 billion facility includes various rate options which can be
elected by Devon, including a rate based on LIBOR plus a margin. The margin is
based on Devon's debt rating. Based on Devon's current debt rating, the margin
is 100 basis points. As of November 30, 2002, the average interest rate on this
facility was 2.7%.
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 six months. Borrowings under the Canadian facility,
currently set at $275 million, may be made 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 45 to 125 basis points based upon usage and the tranche
utilized, and the current Bankers Acceptance margin is 72.5 basis points over
the cost of funding. There were no borrowings under these facilities at November
30, 2002.
Devon also borrows under a $150 million Canadian dollar letter of
credit facility which is primarily used to issue letters of credit in
association with Devon's Canadian drilling commitments. As of November 30, 2002,
there were $106 million Canadian
9
dollars of issued letters of credit under this facility. Devon may also use this
facility for general corporate purposes.
From time to time, Devon also borrows under its commercial paper
facility. Total borrowings under the $725 million U.S. facility and the
commercial paper program cannot exceed $725 million. There were no borrowings
under the commercial paper facility as of November 30, 2002. Recent commercial
paper borrowing costs have been at an average interest rate of 2.1%. Debt
outstanding under this program is generally borrowed for seven 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 $125 million Canadian dollars and
$50 million U.S. dollars of its floating rate debt through swap agreements at
average rates of 6.4% and 5.9%, respectively. The Canadian dollar swap
agreements mature at various dates through July 2007 and the U.S. dollar swap
agreement matures in May 2003.
Devon has also entered into an interest rate swap on its $125 million
8.05% senior notes due in 2004 to swap a fixed interest rate for a variable
interest rate. The variable interest rate on this instrument is based on LIBOR
plus a margin of 336 basis points. The interest rate swap is accounted for as a
fair value hedge under SFAS 133, Accounting for Derivative Instruments and
Hedging Activities.
Devon's interest expense totals have historically included payments of
facility and agency fees, amortization of debt issuance costs, the effect of the
interest rate swaps, and other miscellaneous items not related to the debt
balances outstanding. Devon expects between $10 million and $20 million of such
items to be included in its 2003 interest expense. Based on the information
related to interest expense set forth herein and assuming no material changes in
Devon's levels of indebtedness or prevailing interest rates, Devon expects its
2003 interest expense will be between $512 million and $522 million.
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 plus the cost of
properties not subject to amortization. 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.
Because the ceiling calculation dictates that prices in effect as of
the last day of the applicable quarter are held constant indefinitely, the
resulting value is not indicative
10
of the true fair value of the reserves. Oil and natural gas prices have
historically been cyclical and, on any particular day at the end of a quarter,
can be either substantially higher or lower than Devon's long-term price
forecast that is a barometer for true fair value. Therefore, oil and gas
property writedowns that result from applying the full cost ceiling limitation,
and that are caused by fluctuations in price as opposed to reductions to the
underlying quantities of reserves, should not be viewed as absolute indicators
of a reduction of the ultimate value of the related reserves.
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.
EFFECTS OF CHANGES IN FOREIGN CURRENCY RATES Devon's Canadian
subsidiary has $400 million of fixed-rate senior notes which are denominated in
U.S. dollars. Changes in the exchange rate between the U.S. dollar and the
Canadian dollar during 2003 will increase or decrease the Canadian dollar
equivalent balance of this 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 effect which will be recorded
in 2003. However, based on the November 30, 2002, Canadian-to-U.S. dollar
exchange rate of $0.6389, for every $0.01 change in the exchange rate, Devon
will record a deferred effect (either revenue or expense) of approximately $10
million Canadian dollars. The resulting revenue or expense in U.S. dollars will
depend on the currency exchange rate in effect throughout the year.
OTHER REVENUES Devon's other revenues in 2003 are expected to be
between $23 million and $25 million.
INCOME TAXES Devon's financial income tax rate in 2003 will vary
materially depending on the actual amount of financial pre-tax earnings. The tax
rate for 2003 will be significantly affected by the proportional share of
consolidated pre-tax earnings generated by U.S., Canadian and International
operations due to the different tax rates of each country. There are certain tax
deductions and credits that will have a fixed impact on 2003's income tax
expense regardless of the level of pre-tax earnings that are produced. Given the
uncertainty of its pre-tax earnings amount, Devon estimates that its
consolidated financial income tax rate in 2003 will be between 20% and 40%. The
current income tax rate is expected to be between 5% and 15%. The deferred
income tax rate is expected to be between 15% and 25%. Significant changes in
estimated capital expenditures, production levels of oil, gas and NGLs, the
prices of such products, marketing and midstream revenues, or any of the various
expense items could materially alter the effect of the aforementioned tax
deductions and credits on 2003's financial income tax rates.
YEAR 2003 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
11
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 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 2003 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 2003 capital
expenditures for drilling and development efforts, plus related facilities, to
total between $1.4 billion and $1.6 billion. These amounts include between $455
million and $525 million for drilling and facilities costs related to reserves
expected to be classified as proved as of year-end 2002. In addition, these
amounts include between $485 million and $555 million for other low risk/reward
projects and between $435 million and $510 million for new, higher risk/reward
projects. Low risk/reward projects include development drilling that does not
offset currently productive units and for which there is not a certainty of
continued production from a known productive formation. Higher risk/reward
projects include exploratory drilling to find and produce oil or gas in
previously untested fault blocks or new reservoirs.
The following table shows expected drilling and facilities expenditures
by geographic area.
DRILLING AND PRODUCTION FACILITIES EXPENDITURES
United
States Canada International Total
------------- ------------- ------------- -------------
($ in millions)
Related to Proved Reserves $320-$360 $105-$125 $30-$40 $455-$525
Lower Risk/Reward Projects $335-$375 $150-$180 $0-$0 $485-$555
Higher Risk/Reward Projects $180-$210 $205-$235 $50-$65 $435-$510
------------- ------------- ------------- -------------
Total $835-$945 $460-$540 $80-$105 $1,375-$1,590
============= ============= ============= =============
In addition to the above expenditures for drilling and development,
Devon expects to spend between $150 million to $170 million on its marketing and
midstream assets, which include its oil pipelines, gas processing plants, CO2
removal facilities and gas transport pipelines. Devon also expects to capitalize
between $85 million and $95 million of G&A expenses in accordance with the full
cost method of accounting. Devon also expects to pay between $30 million and $40
million for plugging and abandonment charges, and to spend between $50 million
and $60 million for other 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
12
rate and 157 million shares of common stock outstanding, 2003 dividends are
expected to approximate $31 million. Also, Devon has $150 million of 6.49%
cumulative preferred stock upon which it will pay $10 million of dividends in
2003.
CAPITAL RESOURCES AND LIQUIDITY Devon's estimated 2003 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 2003 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 2003. As of
November 30, 2002, Devon had $975 million available under its $1 billion credit
facilities, net of commercial paper borrowings and outstanding letters of
credit. 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.
13
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
-------------------------------------
Vice President - Accounting
Date: December 10, 2002
14