e8vk
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): May 3, 2006
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
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| DELAWARE
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001-32318
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73-1567067 |
| (State or Other Jurisdiction of
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(Commission File Number)
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(IRS Employer |
| Incorporation or Organization)
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Identification Number) |
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| 20 NORTH BROADWAY, OKLAHOMA CITY, OK
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73102 |
| (Address of Principal Executive Offices)
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(Zip Code) |
Registrant’s telephone number, including area code: (405) 235-3611
Check the appropriate box below if the Form 8-K filing is intended to simultaneously
satisfy the filing obligation of the registrant under any of the following provisions:
o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR
240.14d-2(b))
o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR
240.13e-4(c))
TABLE OF CONTENTS
Item 8.01. Other Events
On May 2, 2006, Devon announced that it will acquire the oil and gas properties of
privately-owned Chief Holdings LLC (“Chief”) for $2.2 billion in cash, including assumed
liabilities. Devon expects to fund the acquisition with approximately $900 million of cash on hand
and approximately $1.3 billion of short-term borrowings under its commercial paper program. Devon
estimates that the acquired properties include proved reserves of 617 billion cubic feet of natural
gas equivalent and leasehold totaling 169,000 net acres located in the Barnett Shale area of Texas.
Devon expects to allocate approximately $1.0 billion of the purchase price to proved reserves and
approximately $1.2 billion to unproved properties. The acquisition is expected to close near the
end of the second quarter of 2006. Therefore, the acquisition of the Chief properties will only
affect Devon’s 2006 operations for the last six months of the year.
Devon reported its original 2006 forward-looking estimates in a Current Report on Form 8-K
dated February 1, 2006, and also in its 2005 Annual Report on
Form 10-K. In this document, Devon is updating certain
of these 2006 forward-looking estimates. Unless otherwise noted, the difference between the
following updated estimates and those originally included in the February 1, 2006 Form 8-K are due to
the effects of the Chief properties for the last half of 2006. The summary section at the end of
this document presents the updated 2006 forward-looking estimates in tabular form both with and without the
effects of the Chief acquisition.
Definitions
The following discussion includes references to various abbreviations relating to volumetric
production terms and other defined terms. These definitions are as follows:
“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.
2
Forward-Looking 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, 2005 Devon and Chief reserve reports 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, 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, cost of goods and services and other risks as outlined below.
Though Devon has completed several major property acquisitions and dispositions in recent
years, these transactions are opportunity driven. Thus, the following forward-looking estimates
exclude the financial and operating effects of potential property acquisitions or divestitures
which may occur during 2006, except for the Chief acquisition.
Also, the financial results of Devon’s foreign operations are subject to currency exchange
rate risks. 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 a
projected average 2006 exchange rate of $0.87 U.S. dollar to $1.00 Canadian dollar. The actual 2006
exchange rate may vary materially from this estimate. Such variations could have a material effect
on these forward-looking estimates.
Additional risks are discussed below in the context of line items most affected by such risks.
A summary of these forward-looking estimates is included at the end of this document.
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, oil, gas and NGL prices may vary considerably due to differences
between regional markets, differing quality of oil produced (i.e., sweet crude versus heavy or sour
crude), differing Btu contents of gas produced, 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 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. Most of Devon’s Canadian
production of oil, natural gas and NGLs is subject to government royalties that fluctuate with
prices. Thus, price fluctuations can affect reported production. Also, Devon’s international
production of oil and natural gas 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.
3
Estimates for future processing and transport 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 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 2006 will be substantially similar to those of 2005, unless otherwise noted.
Geographic Reporting Areas for 2006
The following estimates of production, average price differentials compared to industry
benchmarks and capital expenditures are provided separately for each of the following geographic
areas:
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the United States Onshore; |
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the United States Offshore, which encompasses all oil and gas properties in the Gulf
of Mexico; |
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Canada; and |
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International, which encompasses all oil and gas properties that lie outside of the
United States and Canada. |
Year 2006 Potential Operating Items
Oil, Gas and NGL Production Set forth in the following paragraphs are individual estimates of
oil, gas and NGL production for 2006. On a combined basis, Devon estimates its 2006 oil, gas and
NGL production will total approximately 217 MMBoe.
Devon’s original estimate of 2006 production was 217 MMBoe. As reported in a Form 8-K
furnished on April 6, 2006, Devon lowered this estimate to 215 MMBoe due to lingering delays in
restoring Gulf of Mexico production suspended due to the 2005 hurricanes, and due to delays in
pipeline construction in the Barnett Shale area. The acquisition of the Chief properties is
expected to add approximately 2 MMBoe of production during the last half of 2006, thereby
increasing the 2006 estimate of production back to the original total of 217 MMBoe. Details of the
217 MMBoe by oil, gas and NGL production are included below.
Oil Production Oil production in 2006 is expected to total approximately 57 MMBbls. The
expected production by area is as follows:
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(MMBbls) |
United States Onshore |
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11 |
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United States Offshore |
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8 |
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Canada |
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14 |
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International |
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Oil Prices Devon has not fixed the price it will receive on any of its 2006 oil
production. Devon’s 2006 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 benchmark West Texas Intermediate crude oil delivered at Cushing, Oklahoma.
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Expected Range of Oil Prices |
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as a % of NYMEX Price |
United States Onshore |
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86% to 94% |
United States Offshore |
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86% to 94% |
Canada |
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65% to 75% |
International |
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80% to 88% |
Gas Production Gas production in 2006 is expected to total approximately 826 Bcf.
The expected production by area is as follows:
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(Bcf) |
United States Onshore |
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498 |
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United States Offshore |
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75 |
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Canada |
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243 |
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International |
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Gas Prices Devon’s 2006 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.
Devon currently has no gas hedges in place, although it does have approximately
51,000 Mcf per day of gas production that is subject to fixed-price contracts. The Chief
acquisition will add another 37,000 Mcf per day of gas production during the last half of 2006 that
is subject to either fixed-price contracts, swaps, floors or collars. The combined 88,000 Mcf per
day represents approximately 3% of Devon’s estimated gas production for 2006. Therefore, these
various pricing arrangements are not expected to have a material impact on the ranges of estimated
gas price realizations set forth in the following table.
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Expected Range of Gas Prices |
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as a % of NYMEX Price |
United States Onshore |
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74% to 84% |
United States Offshore |
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92% to 102% |
Canada |
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80% to 90% |
International |
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50% to 70% |
NGL Production Devon expects its 2006 production of NGLs to total approximately 22 MMBbls.
The expected production by area is as follows:
5
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(MMBbls) |
United States Onshore |
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17 |
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United States Offshore |
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1 |
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Canada |
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Marketing and Midstream Revenues and Expenses 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 2006 marketing and midstream revenues will be between
$1.74 billion and $2.20 billion, and marketing and midstream expenses will be between $1.38 billion
and $1.80 billion.
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
the property base, changes in the general price level of services and materials that are used in
the operation of the properties, the amount of repair and workover activity required and changes in
production tax rates. 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 2006 lease operating expenses (including
transportation costs) will be between $1.44 billion and $1.51 billion and production taxes will be
between 3.25% and 3.75% of consolidated oil, natural gas and NGL revenues.
Depreciation, Depletion and Amortization (“DD&A”) The 2006 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 2006 compared to the costs incurred for
such efforts, and the revisions to Devon’s year-end 2005 reserve estimates that, based on prior
experience, are likely to be made during 2006.
Devon’s original estimate of its 2006 oil and gas property DD&A rate was between $9.30 per Boe
and $9.50 per Boe, or between $2.02 billion and $2.06 billion of expense. Prior to the Chief
acquisition, Devon had determined that these 2006 estimates should be increased. Therefore,
excluding the effects of the Chief acquisition, the 2006 oil and gas property DD&A rate has been
increased to between $9.75 per Boe and $10.15 per Boe, which would increase estimated oil and gas
property DD&A expense to between $2.100 billion and $2.185 billion.
The effect of the Chief acquisition for the last six months of 2006 is expected to further
increase the full year 2006 oil and gas property DD&A rate to between $9.90 per Boe and $10.30 per
Boe, which would result in oil and gas property DD&A expense of between $2.145 billion and $2.230
billion.
Additionally, Devon expects its depreciation and amortization expense related to non-oil and
gas property fixed assets to total between $170 million and $180 million.
6
Accretion of Asset Retirement Obligation The 2006 accretion of asset retirement obligation is
expected to be between $48 million and $53 million.
General and Administrative Expenses (“G&A”) Devon’s G&A includes employee compensation and
benefits costs and the costs of many different goods and services used in support of its business.
G&A varies with the level of Devon’s operating activities and the related staffing and professional
services requirements. In addition, employee compensation and benefits costs vary due to various
market factors that affect the level and type of compensation and benefits offered to employees.
Also, goods and services are subject to general price level increases or decreases. Therefore,
significant variances in any of these factors from current expectations could cause actual G&A to
vary materially from the estimate.
Given
these limitations, consolidated G&A in 2006 is expected to be
between $370 million and
$390 million. This estimate includes $35 million of expenses related to restricted stock
compensation costs, net of related capitalization in accordance with the full cost method of
accounting for oil and gas properties. This estimate also includes $35 million of expenses related
to stock option compensation costs, net of related capitalization. Stock option costs are being
expensed beginning January 1, 2006.
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 used are those as of the end of the appropriate quarterly period. These
prices are not changed except where different prices are fixed and determinable from applicable
contracts for the remaining term of those contracts. Such contracts include derivatives accounted
for as cash flow hedges. 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, and requires a 10% discount factor, the
resulting value is not indicative 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.
During the first quarter of 2006, we reduced the carrying value of our Nigerian oil and gas properties by $85 million due to unsuccessful exploratory drilling results. It is not possible to predict whether Devon will incur
other reductions in carrying value in future periods.
Interest Expense Future interest rates and debt outstanding have a significant effect on
Devon’s interest expense. Devon can only marginally influence the prices it will receive in 2006
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.
7
Devon’s original estimate of its 2006 interest expense (net of amounts capitalized) was
between $385 million and $395 million. Prior to the Chief acquisition, Devon had determined that
these 2006 estimates should be increased due to increases in prevailing floating interest rates.
Therefore, excluding the effects of the Chief acquisition, 2006 interest expense will be between
$390 million and $400 million.
The effect of the Chief acquisition for the last six months of 2006 is expected to further
increase the full year 2006 interest expense to between $430 million and $440 million. This
estimate is based on the information related to interest expense set forth below and assumes no
material changes in prevailing interest rates.
The interest expense in 2006 related to Devon’s fixed-rate debt, including net accretion of
related discounts, will be approximately $410 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.
Devon anticipates using approximately $1.3 billion of variable-rate short-term borrowings
under its commercial paper program to fund a portion of the Chief acquisition. Also, Devon has
various debt instruments which have been converted to floating rate debt through the use of
interest rate swaps. Devon’s floating rate debt is as follows:
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Notional |
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Amount |
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Floating Rate |
2.75% notes due in August 2006
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500 |
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LIBOR less 26.8 basis points |
6.55% senior notes due in August
2006
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$171 1
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Banker’s Acceptance plus 340 basis points |
4.375% senior notes due in Oct
2007
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400 |
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LIBOR plus 40 basis points |
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Converted from $200 million Canadian dollars at a Canadian-to-U.S. dollar
exchange rate of $0.8568 as of March 31, 2006. |
Based on future LIBOR rates as of March 31, 2006, interest expense on its floating rate
debt, including net amortization of premiums, is expected to total between $80 million and $90
million in 2006. Excluding the effect of the Chief acquisition, interest expense on floating rate
debt for 2006, including net amortization of premiums, is expected to total between $40 million and
$50 million.
Devon’s interest expense totals include payments of facility and agency fees, amortization of
debt issuance costs, the effect of interest rate swaps not accounted for as hedges, and other
miscellaneous items not related to the debt balances outstanding. Devon expects between $5 million
and $15 million of such items to be included in its 2006 interest expense. Also, Devon expects to
capitalize between $65 million and $75 million of interest during 2006.
Effects of Changes in Foreign Currency Rates Foreign currency gains or losses are not expected
to be material in 2006.
8
Other Revenues Devon’s other revenues in 2006 are expected to be between $135 million and $155
million.
Devon maintains a comprehensive insurance program that includes coverage for physical damage
to its offshore facilities caused by hurricanes. Its insurance program also includes substantial
business interruption coverage which Devon expects to utilize to recover costs associated with the
suspended production related to hurricanes that struck the Gulf of Mexico in the third quarter of
2005. Under the terms of the insurance program, Devon is entitled to be reimbursed for the portion
of production suspended longer than forty-five days, subject to upper limits to oil and natural gas
prices. Also, the terms of the insurance include a standard, per-event deductible of $1 million for
offshore losses as well as a $15 million aggregate annual deductible. Based on current estimates of
physical damage and the anticipated length of time Devon will have production suspended, Devon
expects its policy claims will exceed repair costs and deductible amounts. As a result, 2006 and
2007 other revenues are expected to include more than $150 million for anticipated insurance
proceeds in excess of repair costs. This estimate is dependent upon several variables, including
the actual amount of time that production is suspended, the actual prices in effect while
production is suspended and the timing of collections of insurance proceeds. Based on current
estimates of the timing of collections of insurance proceeds, Devon expects 2006 other revenues
will include $50 million to $70 million for anticipated insurance proceeds, with the balance to be
recorded in 2007. Significant variances in any of these factors from current estimates could cause
actual 2006 other revenues to vary materially from the estimate.
Income Taxes Devon’s financial income tax rate in 2006 will vary materially depending on the
actual amount of financial pre-tax earnings. The tax rate for 2006 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 2006’s income tax expense regardless of the
level of pre-tax earnings that are produced.
Given the uncertainty of pre-tax earnings, Devon expects that its consolidated financial
income tax rate in 2006 will be between 25% and 45%. The current income tax rate is expected to be
between 20% and 30%. The deferred income tax rate is expected to be between 5% and 15%. 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 2006’s financial
income tax rates.
Year 2006 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, except for the Chief
acquisition.
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 2006 capital
expenditures. In addition, if the actual material or labor costs of the budgeted items vary
significantly from the anticipated amounts, actual capital expenditures could vary materially from
Devon’s estimates.
9
Given the limitations discussed, the company expects its 2006 capital expenditures for
drilling and development efforts, plus related facilities, to total between $4.395 billion and
$4.600 billion. These amounts include between $1.255 billion and $1.315 billion for drilling and
facilities costs related to reserves classified as proved as of year-end 2005. In addition, these
amounts include between $2.160 billion and $2.255 billion for other production capital and between
$980 million and $1.030 billion for exploration capital. Other production capital includes
development drilling that does not offset currently productive units and for which there is not a
certainty of continued production from a known productive formation. Exploration capital includes
exploratory drilling to find and produce oil or gas in previously untested fault blocks or new
reservoirs.
The following table shows expected drilling, development and facilities expenditures by
geographic area.
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United |
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United |
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States |
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States |
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Inter- |
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Onshore |
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Offshore |
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Canada |
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national |
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Total |
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(In millions) |
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Production capital related to
proved reserves |
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$ |
420-$440 |
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$ |
85-$95 |
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$ |
530-$550 |
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$ |
220-$230 |
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$ |
1,255-$1,315 |
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Other production capital |
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$ |
1,450-$1,510 |
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$ |
120-$130 |
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$ |
570-$590 |
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$ |
20-$25 |
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$ |
2,160-$2,255 |
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Exploration capital |
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$ |
260-$270 |
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$ |
250-$270 |
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$ |
200-$210 |
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$ |
270-$280 |
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$ |
980-$1,030 |
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Total |
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$ |
2,130-$2,220 |
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$ |
455-$495 |
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$ |
1,300-$1,350 |
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$ |
510-$535 |
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$ |
4,395-$4,600 |
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In addition to the above expenditures for drilling, development and facilities, Devon
expects to spend between $255 million to $275 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 $230 million and $240 million of G&A
expenses in accordance with the full cost method of accounting and to capitalize between $65
million and $75 million of interest. Devon also expects to pay between $35 million and $45 million
for plugging and abandonment charges, and to spend between $130 million and $140 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 $0.1125 per share quarterly dividend rate and 440 million
shares of common stock outstanding as of March 31, 2006, dividends are expected to approximate $197
million. Also, Devon has $150 million of 6.49% cumulative preferred stock upon which it will pay
$10 million of dividends in 2006.
On August 3, 2005, Devon announced its intention to buy back up to 50 million shares of its
common stock. As of May 2, 2006, Devon had repurchased 6.5 million shares under the program for
$387 million. As a result of the Chief acquisition, this repurchase program has been suspended and
will be reevaluated later in 2006.
Capital Resources and Liquidity Devon’s estimated 2006 cash uses, including its drilling and
development activities and repurchase of common stock, are expected to be funded primarily through
a combination of working capital (which totaled $1.3 billion at the end of 2005) and operating cash
flow. In addition, Devon expects to utilize approximately $900 million of cash and approximately
$1.3 billion of short-term borrowings under its commercial paper program to fund the Chief
acquisition. Any remaining cash uses could be funded with borrowings from Devon’s credit facility.
The amount of operating cash flow to be generated during 2006 is uncertain due to the factors
affecting revenues and expenses as previously cited. However, Devon expects its
10
combined capital resources to be more than adequate to fund its anticipated capital
expenditures and other cash uses for 2006.
If significant other acquisitions or other unplanned capital requirements arise during the
year, Devon could utilize its existing credit facility and/or seek to establish and utilize other
sources of financing.
Summary of 2006 Forward-Looking Estimates
The tables below summarize Devon’s 2006 forward-looking estimates both with and without the
estimated effects of the Chief acquisition. As discussed above, we intend to acquire the oil and
gas properties of Chief for $2.2 billion. The acquisition is expected to close near the end of the
second quarter of 2006. Therefore, the acquisition of the Chief properties will only affect Devon’s
2006 operations for the last six months of the year.
| |
|
|
|
|
|
|
|
|
| |
|
Devon |
|
Devon |
| |
|
without Chief |
|
with Chief |
Oil production (MMBbls) |
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
11 |
|
|
|
11 |
|
U.S. Offshore |
|
|
8 |
|
|
|
8 |
|
Canada |
|
|
14 |
|
|
|
14 |
|
International |
|
|
24 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
Total |
|
|
57 |
|
|
|
57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas production (Bcf) |
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
486 |
|
|
|
498 |
|
U.S. Offshore |
|
|
75 |
|
|
|
75 |
|
Canada |
|
|
243 |
|
|
|
243 |
|
International |
|
|
10 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
Total |
|
|
814 |
|
|
|
826 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL production (MMBbls) |
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
17 |
|
|
|
17 |
|
U.S. Offshore |
|
|
1 |
|
|
|
1 |
|
Canada |
|
|
4 |
|
|
|
4 |
|
International |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
Total |
|
|
22 |
|
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (MMBoe) |
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
109 |
|
|
|
111 |
|
U.S. Offshore |
|
|
21 |
|
|
|
21 |
|
Canada |
|
|
59 |
|
|
|
59 |
|
International |
|
|
26 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
Total |
|
|
215 |
|
|
|
217 |
|
|
|
|
|
|
|
|
|
|
11
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Devon without Chief |
|
Devon with Chief |
| |
|
As % of NYMEX Range |
|
As % of NYMEX Range |
| |
|
Low |
|
High |
|
Low |
|
High |
Oil floating price differentials |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
86 |
% |
|
|
94 |
% |
|
|
86 |
% |
|
|
94 |
% |
U.S. Offshore |
|
|
86 |
% |
|
|
94 |
% |
|
|
86 |
% |
|
|
94 |
% |
Canada |
|
|
65 |
% |
|
|
75 |
% |
|
|
65 |
% |
|
|
75 |
% |
International |
|
|
80 |
% |
|
|
88 |
% |
|
|
80 |
% |
|
|
88 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas floating price differentials |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
74 |
% |
|
|
84 |
% |
|
|
74 |
% |
|
|
84 |
% |
U.S. Offshore |
|
|
92 |
% |
|
|
102 |
% |
|
|
92 |
% |
|
|
102 |
% |
Canada |
|
|
80 |
% |
|
|
90 |
% |
|
|
80 |
% |
|
|
90 |
% |
International |
|
|
50 |
% |
|
|
70 |
% |
|
|
50 |
% |
|
|
70 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Devon without Chief |
|
|
Devon with Chief |
|
| |
|
Range |
|
|
Range |
|
| |
|
Low |
|
|
High |
|
|
Low |
|
|
High |
|
Marketing and
midstream ($ in
millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
1,740 |
|
|
$ |
2,200 |
|
|
$ |
1,740 |
|
|
$ |
2,200 |
|
Expenses |
|
$ |
1,380 |
|
|
$ |
1,800 |
|
|
$ |
1,380 |
|
|
$ |
1,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
$ |
360 |
|
|
$ |
400 |
|
|
$ |
360 |
|
|
$ |
400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating
expenses ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOE |
|
$ |
1,430 |
|
|
$ |
1,500 |
|
|
$ |
1,440 |
|
|
$ |
1,510 |
|
Production taxes |
|
|
3.25 |
% |
|
|
3.75 |
% |
|
|
3.25 |
% |
|
|
3.75 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas DD&A |
|
$ |
2,100 |
|
|
$ |
2,185 |
|
|
$ |
2,145 |
|
|
$ |
2,230 |
|
Non-oil and gas DD&A |
|
$ |
170 |
|
|
$ |
180 |
|
|
$ |
170 |
|
|
$ |
180 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
2,270 |
|
|
$ |
2,365 |
|
|
$ |
2,315 |
|
|
$ |
2,410 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas DD&A per Boe |
|
$ |
9.75 |
|
|
$ |
10.15 |
|
|
$ |
9.90 |
|
|
$ |
10.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of ARO |
|
$ |
48 |
|
|
$ |
53 |
|
|
$ |
48 |
|
|
$ |
53 |
|
G&A |
|
$ |
360 |
|
|
$ |
380 |
|
|
$ |
370 |
|
|
$ |
390 |
|
Interest expense |
|
$ |
390 |
|
|
$ |
400 |
|
|
$ |
430 |
|
|
$ |
440 |
|
Other revenues |
|
$ |
155 |
|
|
$ |
175 |
|
|
$ |
135 |
|
|
$ |
155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
20 |
% |
|
|
30 |
% |
|
|
20 |
% |
|
|
30 |
% |
Deferred |
|
|
5 |
% |
|
|
15 |
% |
|
|
5 |
% |
|
|
15 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tax rate |
|
|
25 |
% |
|
|
45 |
% |
|
|
25 |
% |
|
|
45 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
12
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Devon without Chief |
|
|
Devon with Chief |
|
| |
|
Range |
|
|
Range |
|
| |
|
Low |
|
|
High |
|
|
Low |
|
|
High |
|
Production capital
related to proved reserves
($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
370 |
|
|
$ |
390 |
|
|
$ |
420 |
|
|
$ |
440 |
|
U.S. Offshore |
|
$ |
85 |
|
|
$ |
95 |
|
|
$ |
85 |
|
|
$ |
95 |
|
Canada |
|
$ |
530 |
|
|
$ |
550 |
|
|
$ |
530 |
|
|
$ |
550 |
|
International |
|
$ |
220 |
|
|
$ |
230 |
|
|
$ |
220 |
|
|
$ |
230 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,205 |
|
|
$ |
1,265 |
|
|
$ |
1,255 |
|
|
$ |
1,315 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other production capital ($
in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
1,380 |
|
|
$ |
1,430 |
|
|
$ |
1,450 |
|
|
$ |
1,510 |
|
U.S. Offshore |
|
$ |
120 |
|
|
$ |
130 |
|
|
$ |
120 |
|
|
$ |
130 |
|
Canada |
|
$ |
570 |
|
|
$ |
590 |
|
|
$ |
570 |
|
|
$ |
590 |
|
International |
|
$ |
20 |
|
|
$ |
25 |
|
|
$ |
20 |
|
|
$ |
25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2,090 |
|
|
$ |
2,175 |
|
|
$ |
2,160 |
|
|
$ |
2,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration capital ($ in
millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
260 |
|
|
$ |
270 |
|
|
$ |
260 |
|
|
$ |
270 |
|
U.S. Offshore |
|
$ |
250 |
|
|
$ |
270 |
|
|
$ |
250 |
|
|
$ |
270 |
|
Canada |
|
$ |
200 |
|
|
$ |
210 |
|
|
$ |
200 |
|
|
$ |
210 |
|
International |
|
$ |
270 |
|
|
$ |
280 |
|
|
$ |
270 |
|
|
$ |
280 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
980 |
|
|
$ |
1,030 |
|
|
$ |
980 |
|
|
$ |
1,030 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total drilling and facility
capital ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
2,010 |
|
|
$ |
2,090 |
|
|
$ |
2,130 |
|
|
$ |
2,220 |
|
U.S. Offshore |
|
$ |
455 |
|
|
$ |
495 |
|
|
$ |
455 |
|
|
$ |
495 |
|
Canada |
|
$ |
1,300 |
|
|
$ |
1,350 |
|
|
$ |
1,300 |
|
|
$ |
1,350 |
|
International |
|
$ |
510 |
|
|
$ |
535 |
|
|
$ |
510 |
|
|
$ |
535 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
4,275 |
|
|
$ |
4,470 |
|
|
$ |
4,395 |
|
|
$ |
4,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other capital ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing & midstream |
|
$ |
255 |
|
|
$ |
275 |
|
|
$ |
255 |
|
|
$ |
275 |
|
Capitalized G&A |
|
$ |
230 |
|
|
$ |
240 |
|
|
$ |
230 |
|
|
$ |
240 |
|
Capitalized interest |
|
$ |
65 |
|
|
$ |
75 |
|
|
$ |
65 |
|
|
$ |
75 |
|
Plugging and abandonment |
|
$ |
35 |
|
|
$ |
45 |
|
|
$ |
35 |
|
|
$ |
45 |
|
Non-oil and gas |
|
$ |
130 |
|
|
$ |
140 |
|
|
$ |
130 |
|
|
$ |
140 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
715 |
|
|
$ |
775 |
|
|
$ |
715 |
|
|
$ |
775 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 and
|
|
|
|
|
|
|
Chief Accounting Officer |
|
|
Date: May 3, 2006
14