e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2008
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or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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Commission File Number
001-32318
Devon Energy
Corporation
(Exact name of registrant as
specified in its charter)
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Delaware
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73-1567067
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(State of other jurisdiction of
incorporation or organization)
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(I.R.S. Employer identification
No.)
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20 North Broadway, Oklahoma City, Oklahoma
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73102-8260
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(Address of principal executive
offices)
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(Zip
code)
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Registrants telephone number, including area code:
(405) 235-3611
Securities registered pursuant to Section 12(b) of the
Act:
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Title of each class
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Name of each exchange on which registered
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Common stock, par value $0.10 per share
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The New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large accelerated filer
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Accelerated filer
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Non-accelerated
filer o
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Smaller reporting
company o
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(Do not check if a smaller reporting
company)
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
The aggregate market value of the voting common stock held by
non-affiliates of the registrant as of June 29, 2008, was
approximately $53.0 billion, based upon the closing price
of $120.16 per share as reported by the New York Stock Exchange
on such date. On February 16, 2009, 443.8 million
shares of common stock were outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
Proxy statement for the 2009 annual meeting of
stockholders Part III
DEVON
ENERGY CORPORATION
INDEX TO
FORM 10-K
ANNUAL REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION
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DEFINITIONS
As used in this document:
Bbl or Bbls means barrel or barrels.
Bcf means billion cubic feet.
Bcfe means billion cubic feet of gas equivalent,
determined by using the ratio of one Bbl of oil or NGLs to six
Mcf of gas.
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.
Canada means the division of Devon encompassing oil
and gas properties located in Canada.
Domestic means the properties of Devon in the
onshore continental United States and the offshore Gulf of
Mexico.
Federal Funds Rate means the interest rate at which
depository institutions lend balances at the Federal Reserve to
other depository institutions overnight.
FPSO means floating, production, storage and
offloading facilities.
Inside FERC refers to the publication Inside
F.E.R.C.s Gas Market Report.
International means the division of Devon
encompassing oil and gas properties that lie outside the United
States and Canada.
LIBOR means London Interbank Offered Rate.
MBbls means thousand barrels.
MBoe means thousand Boe.
Mcf means thousand cubic feet.
MMBbls means million barrels.
MMBoe means million Boe.
MMBtu means million Btu.
MMcf means million cubic feet.
MMcfe means million cubic feet of gas equivalent,
determined by using the ratio of one Bbl of oil or NGLs to six
Mcf of gas.
NGL or NGLs means natural gas liquids.
NYMEX means New York Mercantile Exchange.
Oil includes crude oil and condensate.
SEC means United States Securities and Exchange
Commission.
U.S. Offshore means the properties of Devon in
the Gulf of Mexico.
U.S. Onshore means the properties of Devon in
the continental United States.
DISCLOSURE
REGARDING FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements
within the meaning of Section 27A of the Securities Act of
1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended. All
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statements other than statements of historical facts included or
incorporated by reference in this report, including, without
limitation, statements regarding our future financial position,
business strategy, budgets, projected revenues, projected costs
and plans and objectives of management for future operations,
are forward-looking statements. Such forward-looking statements
are based on our examination of historical operating trends, the
information used to prepare the December 31, 2008 reserve
reports and other data in our possession or available from third
parties. In addition, forward-looking statements generally can
be identified by the use of forward-looking terminology such as
may, will, expect,
intend, project, estimate,
anticipate, believe, or
continue or similar terminology. Although we believe
that the expectations reflected in such forward-looking
statements are reasonable, we can give no assurance that such
expectations will prove to have been correct. Important factors
that could cause actual results to differ materially from our
expectations include, but are not limited to, our assumptions
about:
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energy markets, including the supply and demand for oil, gas,
NGLs and other products or services, and the prices of oil, gas,
NGLs, including regional pricing differentials, and other
products or services;
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production levels, including Canadian production subject to
government royalties, which fluctuate with prices and
production, and international production governed by payout
agreements, which affect reported production;
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reserve levels;
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competitive conditions;
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technology;
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the availability of capital resources within the securities or
capital markets and related risks such as general credit,
liquidity, market and interest-rate risks;
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capital expenditure and other contractual obligations;
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currency exchange rates;
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the weather;
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inflation;
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the availability of goods and services;
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drilling risks;
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future processing volumes and pipeline throughput;
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general economic conditions, whether internationally, nationally
or in the jurisdictions in which we or our subsidiaries conduct
business;
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legislative or regulatory changes, including retroactive royalty
or production tax regimes, changes in environmental regulation,
environmental risks and liability under federal, state and
foreign environmental laws and regulations;
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terrorism;
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occurrence of property acquisitions or divestitures; and
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other factors disclosed under Item 2.
Properties Proved Reserves and Estimated Future Net
Revenue, Item 7. Managements Discussion
and Analysis of Financial Condition and Results of
Operations, Item 7A. Quantitative and
Qualitative Disclosures About Market Risk and elsewhere in
this report.
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All subsequent written and oral forward-looking statements
attributable to Devon, or persons acting on its behalf, are
expressly qualified in their entirety by the cautionary
statements. We assume no duty to update or revise our
forward-looking statements based on changes in internal
estimates or expectations or otherwise.
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PART I
General
Devon Energy Corporation, including its subsidiaries
(Devon), is an independent energy company engaged
primarily in oil and gas exploration, development and
production, the transportation of oil, gas, and NGLs and the
processing of natural gas. We own oil and gas properties
principally in the United States and Canada and, to a lesser
degree, various regions located outside North America, including
Azerbaijan, Brazil and China. In addition to our oil and gas
operations, we have marketing and midstream operations primarily
in North America. These include marketing gas, crude oil and
NGLs, and constructing and operating pipelines, storage and
treating facilities and natural gas processing plants. A
detailed description of our significant properties and
associated 2008 developments can be found under
Item 2. Properties.
We began operations in 1971 as a privately held company. In
1988, our common stock began trading publicly on the American
Stock Exchange under the symbol DVN. In October
2004, we transferred our common stock listing to the New York
Stock Exchange. Our principal and administrative offices are
located at 20 North Broadway, Oklahoma City, OK
73102-8260
(telephone 405/235-3611).
Strategy
We have a two-pronged operating strategy. First, we invest a
significant portion of our capital budget in low-risk
development projects on our extensive North American property
base, which provides reliable and repeatable production and
reserves additions. To supplement that low-risk part of our
strategy, we also annually invest capital in long cycle-time
projects to replenish our development inventory for the future.
The philosophy that underlies the execution of this strategy is
to strive to increase value on a per share basis by:
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building oil and gas reserves and production;
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exercising capital discipline;
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controlling operating costs;
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improving performance through our marketing and midstream
operations; and
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preserving financial flexibility.
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Development
of Business
During 1988, we expanded our capital base with our first
issuance of common stock to the public. This transaction began a
substantial expansion program that has continued through the
subsequent years. This expansion is attributable to both a
focused mergers and acquisitions program spanning a number of
years and an active ongoing exploration and development drilling
program. We have increased our total proved reserves from
8 MMBoe1
at year-end 1987 to 2,428 MMBoe at year-end 2008.
During the same time period, we have grown proved reserves from
0.66 Boe1
per diluted share at the end of 1987 to 5.44 Boe per diluted
share at the end of 2008. This represents a compound annual
growth rate of 11%. We have also increased production from 0.09
Boe1 per
diluted share in 1987 to 0.53 Boe per diluted share in 2008, for
a compound annual growth rate of 9%. This per share growth is a
direct result of successful execution of our strategic plan and
other key transactions and events.
We achieved a number of significant accomplishments in our
operations during 2008, including those discussed below.
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Drilling Success We drilled a record
2,441 gross wells with an overall 98% rate of success. As a
result of our success with the drill-bit, we replaced
approximately 245% of our 2008 production. We
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1 Excludes
the effects of mergers in 1998 and 2000 that were accounted for
as poolings of interests.
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added 584 MMBoe of proved reserves during the year with
extensions, discoveries and performance revisions, a total which
was well in excess of the 238 MMBoe we produced during the
year. Consistent with our two-pronged operating strategy, 93% of
the wells we drilled were North American development wells,
which was the main driver behind our 6% increase in production
in 2008.
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Barnett Shale Growth We continue to retain
our positions as the largest producer and largest lease holder
in the Barnett Shale area of north Texas. We increased our
production from the Barnett Shale area by 31% in 2008, exiting
the year at 1.2 Bcfe per day net to our ownership interest.
We drilled 659 wells in the Barnett Shale in 2008. We have
interests in approximately 3,800 producing wells in the Barnett
Shale and hold approximately 715,000 net acres of Barnett
Shale leases. At December 31, 2008, we had estimated proved
reserves of 894 MMBoe in the Barnett Shale area.
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U.S. Onshore Production and Reserves Growth
Our U.S. onshore properties, including the Barnett
Shale, the Groesbeck and Carthage areas in east Texas, the
Washakie basin in Wyoming and the Woodford Shale area in
Oklahoma, showed strong production growth in 2008. These four
areas, which accounted for approximately 69% of our
U.S. onshore production, had production growth in 2008 of
26% compared to 2007.
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We also completed construction and commenced operation of our
Northridge natural gas processing plant in southeastern
Oklahoma. This plant can process up to 200 MMcf of natural
gas per day and will support our growing production in the
Woodford Shale.
We have also leveraged our knowledge of and expertise in the
Barnett Shale into other unconventional natural gas plays, such
as the Haynesville shale in eastern Texas and western Louisiana,
the Cana shale play in western Oklahoma and the Cody play in
Montana. We added approximately 800,000 net undeveloped
acres to our lease inventory, positioning us with more than
1.4 million net acres in emerging unconventional natural
gas plays.
In addition to production growth, our U.S. onshore
properties also demonstrated measurable growth in proved
reserves. U.S. onshore proved reserves grew 416 MMBoe
due to extensions, discoveries and performance revisions. This
was almost three times our U.S. onshore production in 2008
of 146 MMBoe. Our drilling activities increased our 2008
U.S. onshore proved reserves by 27% compared to the end of
2007.
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Marketing and Midstream Our marketing and
midstream business delivered another record setting year with
operating profit increasing by 31% to $668 million.
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Jackfish We ramped up production from our
100%-owned Jackfish thermal heavy oil project in the Alberta oil
sands to 22,000 Bbls per day by the end of the year. In
2009, we expect to achieve our peak production target of
35,000 Bbls per day. Additionally, we received regulatory
approval for the second phase of Jackfish. Like the first phase,
this second phase of Jackfish is also expected to eventually
produce 35,000 Bbls per day.
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Lloydminster Also in Canada, we increased
production from the Lloydminster heavy oil play in Alberta by
14%, exiting the year at approximately 45,000 Boe per day. We
drilled 425 wells at Lloydminster in 2008, which added
19 MMBoe of proved reserves.
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Divestiture of African Properties We
substantially completed our Egypt and West Africa divestiture
programs. We have now sold all of our oil and gas producing
properties in Africa. These divestitures generated just over
$3.0 billion of sales proceeds. After income taxes and
purchase price adjustments, such proceeds totaled
$2.2 billion and generated after-tax gains of
$0.8 billion.
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Pursuant to accounting rules for discontinued operations, the
amounts in this document related to continuing operations for
2008 and all prior years presented do not include amounts
related to our operations in Egypt and West Africa.
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Polvo We experienced numerous mechanical
issues with our offshore development project that delayed our
expected production growth. By the end of 2008, we had solved
the mechanical issues and
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are now producing at 17,000 Bbls per day. We expect
production to increase in 2009. We have a 60% working interest
in Polvo.
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Gulf of Mexico Exploration and Development We
continued to build off prior years successful drilling
results with our deepwater Gulf of Mexico exploration and
development program. To date, we have drilled four discovery
wells in the Lower Tertiary trend Cascade in 2002
(50% working interest), St. Malo in 2003 (25% working interest),
Jack in 2004 (25% working interest) and Kaskida in 2006 (30%
working interest). These achievements, along with our 2008
developments discussed below, support our positive view of the
Lower Tertiary and demonstrate the potential of our exploration
strategy on growth of long-term production, reserves and value.
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Specific Gulf of Mexico developments in 2008 included the
following:
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At Cascade, we commenced drilling the first of two initial
producing wells and continued work on the production facilities
and subsea equipment. We anticipate first production at Cascade
in 2010. When Cascade begins producing, it will utilize the
Gulfs first FPSO.
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At Jack and St. Malo, our partners focused on development
concepts for the two fields. Particular consideration has been
given to joint development of the two fields that could employ
the use of a single, semi-submersible production facility.
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At Kaskida, the largest of our Lower Tertiary discoveries, we
are currently drilling an appraisal well.
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Financial
Information about Segments and Geographical Areas
Notes 18 and 20 to the consolidated financial statements
included in Item 8. Financial Statements and
Supplementary Data of this report contain information on
our segments and geographical areas.
Oil,
Natural Gas and NGL Marketing
The spot markets for oil, gas and NGLs are subject to volatility
as supply and demand factors fluctuate. As detailed below, we
sell our production under both long-term (one year or more) or
short-term (less than one year) agreements. Regardless of the
term of the contract, the vast majority of our production is
sold at variable or market sensitive prices.
Additionally, we may periodically enter into financial hedging
arrangements, fixed-price contracts or firm delivery commitments
with a portion of our oil and gas production. These activities
are intended to support targeted price levels and to manage our
exposure to price fluctuations. See Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
Oil
Marketing
Our oil production is sold under both long-term (one year or
more) and short-term (less than one year) agreements at prices
negotiated with third parties. As of February 2009, all of our
oil production was sold at variable or market-sensitive prices.
Natural
Gas Marketing
Our gas production is also sold under both long-term and
short-term agreements at prices negotiated with third parties.
Although exact percentages vary daily, as of February 2009,
approximately 75% of our gas production was sold under
short-term contracts at variable or market-sensitive prices.
These market-sensitive sales are referred to as spot
market sales. Another 24% of our production was committed
under various long-term contracts, which dedicate the gas to a
purchaser for an extended period of time, but still at market
sensitive prices. The remaining 1% of our gas production was
sold under long-term, fixed-price contracts.
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NGL
Marketing
Our NGL production is sold under both long-term and short-term
agreements at prices negotiated with third parties. Although
exact percentages vary, as of February 2009, approximately 97%
of our NGL production was sold under short-term contracts at
variable or market-sensitive prices. The remaining NGL
production is sold under long-term, market-indexed contracts
which are subject to market pricing variations.
Marketing
and Midstream Activities
The primary objective of our marketing and midstream operations
is to add value to us and other producers to whom we provide
such services by gathering, processing and marketing oil, gas
and NGL production in a timely and efficient manner. Our most
significant midstream asset is the Bridgeport processing plant
and gathering system located in north Texas. These facilities
serve not only our gas production from the Barnett Shale but
also gas production of other producers in the area. Our
midstream assets also include our 50% interest in the Access
Pipeline transportation system in Canada. This pipeline system
allows us to blend our Jackfish heavy oil production with
condensate and then transport the combined product to the
Edmonton area for sale.
Our marketing and midstream revenues are primarily generated by:
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selling NGLs that are either extracted from the gas streams
processed by our plants or purchased from third parties for
marketing, and
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selling or gathering gas that moves through our transport
pipelines and unrelated third-party pipelines.
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Our marketing and midstream costs and expenses are primarily
incurred from:
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purchasing the gas streams entering our transport pipelines and
plants;
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purchasing fuel needed to operate our plants, compressors and
related pipeline facilities;
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purchasing third-party NGLs;
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operating our plants, gathering systems and related
facilities; and
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transporting products on unrelated third-party pipelines.
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Customers
We sell our gas production to a variety of customers including
pipelines, utilities, gas marketing firms, industrial users and
local distribution companies. Gathering systems and interstate
and intrastate pipelines are used to consummate gas sales and
deliveries.
The principal customers for our crude oil production are
refiners, remarketers and other companies, some of which have
pipeline facilities near the producing properties. In the event
pipeline facilities are not conveniently available, crude oil is
trucked or shipped to storage, refining or pipeline facilities.
Our NGL production is primarily sold to customers engaged in
petrochemical, refining and heavy oil blending activities.
Pipelines, railcars and trucks are utilized to move our products
to market.
No purchaser accounted for over 10% of our revenues in 2008,
2007 or 2006.
Seasonal
Nature of Business
Generally, but not always, the demand for natural gas decreases
during the summer months and increases during the winter months.
Seasonal anomalies such as mild winters or hot summers sometimes
lessen this fluctuation. In addition, pipelines, utilities,
local distribution companies and industrial users utilize
natural gas storage facilities and purchase some of their
anticipated winter requirements during the summer. This can also
lessen seasonal demand fluctuations.
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Government
Regulation
The oil and gas industry is subject to various types of
regulation throughout the world. Legislation affecting the oil
and gas industry has been pervasive and is under constant review
for amendment or expansion. Pursuant to this legislation,
numerous government agencies have issued extensive laws and
regulations binding on the oil and gas industry and its
individual members, some of which carry substantial penalties
for failure to comply. Such laws and regulations have a
significant impact on oil and gas exploration, production and
marketing and midstream activities. These laws and regulations
increase the cost of doing business and, consequently, affect
profitability. Because new legislation affecting the oil and gas
industry is commonplace and existing laws and regulations are
frequently amended or reinterpreted, we are unable to predict
the future cost or impact of complying with such laws and
regulations. However, we do not expect that any of these laws
and regulations will affect our operations in a manner
materially different than they would affect other oil and gas
companies of similar size and financial strength.
The following are significant areas of government control and
regulation in the United States, Canada and other international
locations in which we operate.
Exploration
and Production Regulation
Our oil and gas operations are subject to various federal,
state, provincial, tribal, local and international laws and
regulations, including, but not limited to, laws and regulations
related to the acquisition of seismic data; the location of
wells; drilling and casing of wells; well production; spill
prevention plans; emissions permitting; the use, transportation,
storage and disposal of fluids and materials incidental to oil
and gas operations; surface usage and the restoration of
properties upon which wells have been drilled; the calculation
and disbursement of royalty payments and production taxes; the
plugging and abandoning of wells; the transportation of
production; and, in international operations, minimum
investments in the country of operations.
Our operations are also subject to conservation regulations,
including the regulation of the size of drilling and spacing
units or proration units; the number of wells that may be
drilled in a unit; the rate of production allowable from oil and
gas wells; and the unitization or pooling of oil and gas
properties. In the United States, some states allow the forced
pooling or integration of tracts to facilitate exploration,
while other states rely on voluntary pooling of lands and
leases, which may make it more difficult to develop oil and gas
properties. In addition, state conservation laws generally limit
the venting or flaring of natural gas and impose certain
requirements regarding the ratable purchase of production. The
effect of these regulations is to limit the amounts of oil and
gas we can produce from our wells and to limit the number of
wells or the locations at which we can drill.
Certain of our U.S. oil and gas leases are granted by the
federal government and administered by various federal agencies,
including the Bureau of Land Management and the Minerals
Management Service (MMS) of the Department of the
Interior. Such leases require compliance with detailed federal
regulations and orders that regulate, among other matters,
drilling and operations on lands covered by these leases, and
calculation and disbursement of royalty payments to the federal
government. The MMS has been particularly active in recent years
in evaluating and, in some cases, promulgating new rules and
regulations regarding competitive lease bidding and royalty
payment obligations for production from federal lands. The
Federal Energy Regulatory Commission also has jurisdiction over
certain U.S. offshore activities pursuant to the Outer
Continental Shelf Lands Act.
Royalties
and Incentives in Canada
The royalty system in Canada is a significant factor in the
profitability of oil and gas production. Royalties payable on
production from lands other than Crown lands are determined by
negotiations between the parties. Crown royalties are determined
by government regulation and are generally calculated as a
percentage of the value of the gross production, with the
royalty rate dependent in part upon prescribed reference prices,
well productivity, geographical location, field discovery date
and the type and quality of the petroleum product produced. From
time to time, the federal and provincial governments of Canada
have also
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established incentive programs such as royalty rate reductions,
royalty holidays and tax credits for the purpose of encouraging
oil and gas exploration or enhanced recovery projects. These
incentives generally have the effect of increasing our revenues,
earnings and cash flow.
In December 2008, the provincial government of Alberta enacted a
new royalty regime. The new regime provides for new royalties
for conventional oil, gas, NGL and bitumen production effective
January 1, 2009. The royalties are linked to price and
production levels and apply to both new and existing
conventional oil and gas activities and oil sands projects.
This royalty regime reduced our proved reserves as of
December 31, 2008 by 28 MMBoe. Additionally, this
regime is expected to reduce future earnings and cash flows from
our oil and gas properties located in Alberta. The actual effect
on our future earnings and cash flows of this royalty regime
will be determined based on, among other things, our production
rates from wells in Alberta, the proportion of our Alberta
production to our overall production, our product mix in
Alberta, commodity prices and foreign exchange rates.
Pricing
and Marketing in Canada
Any oil or gas export to be made pursuant to an export contract
of a certain duration or covering a certain quantity requires an
exporter to obtain an export permit from Canadas National
Energy Board (NEB). The governments of Alberta,
British Columbia and Saskatchewan also regulate the volume of
natural gas that may be removed from those provinces for
consumption elsewhere.
Investment
Canada Act
The Investment Canada Act requires federal government of Canada
approval, in certain cases, of the acquisition of control of a
Canadian business by an entity that is not controlled by
Canadians. In certain circumstances, the acquisition of natural
resource properties may be considered to be a transaction
requiring such approval.
Production
Sharing Contracts
Some of our international licenses are governed by production
sharing contracts (PSCs) between the concessionaires
and the granting government agency. PSCs are contracts that
define and regulate the framework for investments, revenue
sharing, and taxation of mineral interests in foreign countries.
Unlike most domestic leases, PSCs have defined production terms
and time limits of generally 30 years. PSCs also generally
contain sliding scale revenue sharing provisions. As a result,
at either higher production rates or higher cumulative rates of
return, PSCs generally allow the government agency to retain
higher fractions of revenue.
Environmental
and Occupational Regulations
We are subject to various federal, state, provincial, tribal,
local and international laws and regulations concerning
occupational safety and health as well as the discharge of
materials into, and the protection of, the environment.
Environmental laws and regulations relate to, among other
things, assessing the environmental impact of seismic
acquisition, drilling or construction activities; the
generation, storage, transportation and disposal of waste
materials; the emission of certain gases into the atmosphere;
the monitoring, abandonment, reclamation and remediation of well
and other sites, including sites of former operations; and the
development of emergency response and spill contingency plans.
The application of worldwide standards, such as ISO 14000
governing Environmental Management Systems, is required to be
implemented for some international oil and gas operations.
In 1997, numerous countries participated in an international
conference under the United Nations Framework Convention on
Climate Change and adopted an agreement known as the Kyoto
Protocol (the Protocol). The Protocol became
effective February 16, 2005, and requires reductions of
certain emissions that contribute to atmospheric levels of
greenhouse gases (GHG). Certain countries in which
we operate (but
10
not the United States) have ratified the Protocol. Pursuant to
its ratification of the Protocol in April 2007, the federal
government of Canada released its Regulatory Framework for Air
Emissions, a plan to implement mandatory reductions in GHG
emissions by way of regulation under existing legislation. The
mandatory reductions on GHG emissions will create additional
costs for the Canadian oil and gas industry. Certain provinces
in Canada have also implemented legislation and regulations to
reduce GHG emissions, which will also have a cost associated
with compliance. Presently, it is not possible to accurately
estimate the costs we could incur to comply with any laws or
regulations developed to achieve emissions reductions in Canada
or elsewhere, but such expenditures could be substantial.
In 2006, we published our Corporate Climate Change Position and
Strategy. Key components of the strategy include initiation of
energy efficiency measures, tracking emerging climate change
legislation and publication of a corporate GHG emission
inventory, which occurred in January 2008. Devon continues to
explore energy efficiency measures and greenhouse gas emission
reduction opportunities. We also continue to monitor legislative
and regulatory climate change developments. All provisions of
the strategy are completed or are in progress.
We consider the costs of environmental protection and safety and
health compliance necessary and manageable parts of our
business. With the efforts of our Environmental, Health and
Safety Department, we have been able to plan for and comply with
environmental, safety and health initiatives without materially
altering our operating strategy. We anticipate making increased
expenditures of both a capital and expense nature as a result of
the increasingly stringent laws relating to the protection of
the environment and safety and health compliance. While our
unreimbursed expenditures in 2008 attributable to such matters
were immaterial, we cannot predict with any reasonable degree of
certainty our future exposure concerning such matters.
We maintain levels of insurance customary in the industry to
limit our financial exposure in the event of a substantial
environmental claim resulting from sudden, unanticipated and
accidental discharges of oil, salt water or other substances.
However, we do not maintain 100% coverage concerning any
environmental claim, and no coverage is maintained with respect
to any penalty or fine required to be paid because of a
violation of law.
Employees
As of December 31, 2008, we had approximately
5,500 employees. We consider labor relations with our
employees to be satisfactory. We have not had any work stoppages
or strikes pertaining to our employees.
Competition
See Item 1A. Risk Factors.
Availability
of Reports
Through our website,
http://www.devonenergy.com,
we make available electronic copies of the charters of the
committees of our Board of Directors, other documents related to
our corporate governance (including our Code of Ethics for the
Chief Executive Officer, Chief Financial Officer and Chief
Accounting Officer), and documents we file or furnish to the
SEC, including our annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
and current reports on
Form 8-K,
as well as any amendments to these reports. Access to these
electronic filings is available free of charge as soon as
reasonably practicable after filing or furnishing them to the
SEC. Printed copies of our committee charters or other
governance documents and filings can be requested by writing to
our corporate secretary at the address on the cover of this
report.
11
Our business activities, and the oil and gas industry in
general, are subject to a variety of risks. If any of the
following risk factors should occur, our profitability,
financial condition or liquidity could be materially impacted.
As a result, holders of our securities could lose part or all of
their investment in Devon.
Oil, Gas
and NGL Prices are Volatile
Our financial results are highly dependent on the prices of and
demand for oil, gas and NGLs. A significant downward movement of
the prices for these commodities could have a material adverse
effect on our revenues, operating cash flows and profitability.
Such a downward price movement could also have a material
adverse effect on our estimated proved reserves, the carrying
value of our oil and gas properties, the level of planned
drilling activities and future growth. Historically, prices have
been volatile and are likely to continue to be volatile in the
future due to numerous factors beyond our control. These factors
include, but are not limited to:
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consumer demand for oil, gas and NGLs;
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conservation efforts;
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OPEC production levels;
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weather;
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regional pricing differentials;
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differing quality of oil produced (i.e., sweet crude versus
heavy or sour crude) and Btu content of gas produced;
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the level of imports and exports of oil, gas and NGLs;
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the price and availability of alternative fuels;
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the overall economic environment; and
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governmental regulations and taxes.
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Estimates
of Oil, Gas and NGL Reserves are Uncertain
The process of estimating oil, gas and NGL reserves is complex
and requires significant judgment in the evaluation of available
geological, engineering and economic data for each reservoir,
particularly for new discoveries. Because of the high degree of
judgment involved, different reserve engineers may develop
different estimates of reserve quantities and related revenue
based on the same data. In addition, the reserve estimates for a
given reservoir may change substantially over time as a result
of several factors including additional development activity,
the viability of production under varying economic conditions
and variations in production levels and associated costs.
Consequently, material revisions to existing reserve estimates
may occur as a result of changes in any of these factors. Such
revisions to proved reserves could have a material adverse
effect on our estimates of future net revenue, as well as our
financial condition and profitability. Additional discussion of
our policies regarding estimating and recording reserves is
described in Item 2. Properties Proved
Reserves and Estimated Future Net Revenue.
Discoveries
or Acquisitions of Additional Reserves are Needed to Avoid a
Material Decline in Reserves and Production
The production rates from oil and gas properties generally
decline as reserves are depleted, while related per unit
production costs generally increase, due to decreasing reservoir
pressures and other factors. Therefore, our estimated proved
reserves and future oil, gas and NGL production will decline
materially as reserves are produced unless we conduct successful
exploration and development activities or, through engineering
studies, identify additional producing zones in existing wells,
secondary recovery reserves or tertiary recovery reserves, or
acquire additional properties containing proved reserves.
Consequently, our future oil, gas and NGL
12
production and related per unit production costs are highly
dependent upon our level of success in finding or acquiring
additional reserves.
Future
Exploration and Drilling Results are Uncertain and Involve
Substantial Costs
Substantial costs are often required to locate and acquire
properties and drill exploratory wells. Such activities are
subject to numerous risks, including the risk that we will not
encounter commercially productive oil or gas reservoirs. The
costs of drilling and completing wells are often uncertain. In
addition, oil and gas properties can become damaged or drilling
operations may be curtailed, delayed or canceled as a result of
a variety of factors including, but not limited to:
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unexpected drilling conditions;
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pressure or irregularities in reservoir formations;
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equipment failures or accidents;
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fires, explosions, blowouts and surface cratering;
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marine risks such as capsizing, collisions and hurricanes;
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other adverse weather conditions;
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lack of access to pipelines or other transportation methods;
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environmental hazards or liabilities; and
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shortages or delays in the availability of services or delivery
of equipment.
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A significant occurrence of one of these factors could result in
a partial or total loss of our investment in a particular
property. In addition, drilling activities may not be successful
in establishing proved reserves. Such a failure could have an
adverse effect on our future results of operations and financial
condition. While both exploratory and developmental drilling
activities involve these risks, exploratory drilling involves
greater risks of dry holes or failure to find commercial
quantities of hydrocarbons. We are currently performing
exploratory drilling activities in certain international
countries. We have been granted drilling concessions in these
countries that require commitments on our behalf to incur
capital expenditures. Even if future drilling activities are
unsuccessful in establishing proved reserves, we will likely be
required to fulfill our commitments to make such capital
expenditures.
Industry
Competition For Leases, Materials, People and Capital Can Be
Significant
Strong competition exists in all sectors of the oil and gas
industry. We compete with major integrated and other independent
oil and gas companies for the acquisition of oil and gas leases
and properties. We also compete for the equipment and personnel
required to explore, develop and operate properties. Competition
is also prevalent in the marketing of oil, gas and NGLs.
Typically, during times of high or rising commodity prices,
drilling and operating costs will also increase. Higher prices
will also generally increase the costs of properties available
for acquisition. Certain of our competitors have financial and
other resources substantially larger than ours, and they have
also established strategic long-term positions and maintain
strong governmental relationships in countries in which we may
seek new entry. As a consequence, we may be at a competitive
disadvantage in bidding for drilling rights. In addition, many
of our larger competitors may have a competitive advantage when
responding to factors that affect demand for oil and gas
production, such as changing worldwide price and production
levels, the cost and availability of alternative fuels, and the
application of government regulations.
13
International
Operations Have Uncertain Political, Economic and Other
Risks
Our operations outside North America are based primarily in
Azerbaijan, Brazil and China. We face political and economic
risks and other uncertainties in these areas that are more
prevalent than what exist for our operations in North America.
Such factors include, but are not limited to:
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general strikes and civil unrest;
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the risk of war, acts of terrorism, expropriation, forced
renegotiation or modification of existing contracts;
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import and export regulations;
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taxation policies, including royalty and tax increases and
retroactive tax claims, and investment restrictions;
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transportation regulations and tariffs;
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exchange controls, currency fluctuations, devaluation or other
activities that limit or disrupt markets and restrict payments
or the movement of funds;
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laws and policies of the United States affecting foreign trade,
including trade sanctions;
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the possibility of being subject to exclusive jurisdiction of
foreign courts in connection with legal disputes relating to
licenses to operate and concession rights in countries where we
currently operate;
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the possible inability to subject foreign persons to the
jurisdiction of courts in the United States; and
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difficulties enforcing our rights against a governmental agency
because of the doctrine of sovereign immunity and foreign
sovereignty over international operations.
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Foreign countries have occasionally asserted rights to oil and
gas properties through border disputes. If a country claims
superior rights to oil and gas leases or concessions granted to
us by another country, our interests could decrease in value or
be lost. Even our smaller international assets may affect our
overall business and results of operations by distracting
managements attention from our more significant assets.
Various regions of the world have a history of political and
economic instability. This instability could result in new
governments or the adoption of new policies that might result in
a substantially more hostile attitude toward foreign investment.
In an extreme case, such a change could result in termination of
contract rights and expropriation of foreign-owned assets. This
could adversely affect our interests and our future
profitability.
The impact that future terrorist attacks or regional hostilities
may have on the oil and gas industry in general, and on our
operations in particular, is not known at this time. Uncertainty
surrounding military strikes or a sustained military campaign
may affect our operations in unpredictable ways, including
disruptions of fuel supplies and markets, particularly oil, and
the possibility that infrastructure facilities, including
pipelines, production facilities, processing plants and
refineries, could be direct targets of, or indirect casualties
of, an act of terror or war. We may be required to incur
significant costs in the future to safeguard our assets against
terrorist activities.
Government
Laws and Regulations Can Change
Our operations are subject to federal laws and regulations in
the United States, Canada and the other countries in which we
operate. In addition, we are also subject to the laws and
regulations of various states, provinces, tribal and local
governments. Pursuant to such legislation, numerous government
departments and agencies have issued extensive rules and
regulations binding on the oil and gas industry and its
individual members, some of which carry substantial penalties
for failure to comply. Changes in such legislation have
affected, and at times in the future could affect, our
operations. Political developments can restrict production
levels, enact price controls, change environmental protection
requirements, and increase taxes, royalties and other amounts
payable to governments or governmental agencies. Although we are
unable to predict changes to existing laws and regulations, such
changes could significantly impact our profitability. While such
14
legislation can change at any time in the future, those laws and
regulations outside North America to which we are subject
generally include greater risk of unforeseen change.
Environmental
Matters and Costs Can Be Significant
As an owner, lessee or operator of oil and gas properties, we
are subject to various federal, state, provincial, tribal, local
and international laws and regulations relating to discharge of
materials into, and protection of, the environment. These laws
and regulations may, among other things, impose liability on us
for the cost of pollution
clean-up
resulting from our operations in affected areas. Any future
environmental costs of fulfilling our commitments to the
environment are uncertain and will be governed by several
factors, including future changes to regulatory requirements.
There is no assurance that changes in or additions to laws or
regulations regarding the protection of the environment will not
have a significant impact on our operations and profitability.
Insurance
Does Not Cover All Risks
Exploration, development, production and processing of oil, gas
and NGLs can be hazardous and involve unforeseen occurrences
such as hurricanes, blowouts, cratering, fires and loss of well
control. These occurrences can result in damage to or
destruction of wells or production facilities, injury to
persons, loss of life, or damage to property or the environment.
We maintain insurance against certain losses or liabilities in
accordance with customary industry practices and in amounts that
management believes to be prudent. However, insurance against
all operational risks is not available to us. Due to changes in
the insurance marketplace following hurricanes in the Gulf of
Mexico in recent years, we currently do not have coverage for
any damage that may be caused by future named windstorms in the
Gulf of Mexico.
Certain
of Our Investments Are Subject To Risks That May Affect Their
Liquidity and Value
To maximize earnings on available cash balances, we periodically
invest in securities that we consider to be short-term in nature
and generally available for short-term liquidity needs. During
2007, we purchased asset-backed securities that have an auction
rate reset feature (auction rate securities). Our
auction rate securities generally have contractual maturities of
more than 20 years. However, the underlying interest rates
on our securities are scheduled to reset every seven to
28 days. Therefore, when we bought these securities, they
were generally priced and subsequently traded as short-term
investments because of the interest rate reset feature. At
December 31, 2008, our auction rate securities totaled
$122 million.
Since February 8, 2008, we have experienced difficulty
selling our securities due to the failure of the auction
mechanism, which provided liquidity to these securities. An
auction failure means that the parties wishing to sell
securities could not do so. The securities for which auctions
have failed will continue to accrue interest and be auctioned
every seven to 28 days until the auction succeeds, the
issuer calls the securities or the securities mature. Due to
continued auction failures throughout 2008, we consider these
investments to be long-term in nature and generally not
available for short-term liquidity needs.
Our auction rate securities are rated AAA the
highest rating by one or more rating agencies and
are collateralized by student loans that are substantially
guaranteed by the United States government. These investments
are subject to general credit, liquidity, market and interest
rate risks, which may be exacerbated by continued problems in
the global credit markets, including but not limited to,
U.S. subprime mortgage defaults, writedowns by major
financial institutions due to deteriorating values of their
asset portfolios (including leveraged loans, collateralized debt
obligations, credit default swaps, and other credit-linked
products). These and other related factors have affected various
sectors of the financial markets and caused credit and liquidity
issues. If issuers are unable to successfully close future
auctions and their credit ratings deteriorate, our ability to
liquidate these securities and fully recover the carrying value
of our investment in the near term may be limited. Under such
circumstances, we may record an impairment charge on these
investments in the future.
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Item 1B.
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Unresolved
Staff Comments
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Not applicable.
15
Substantially all of our properties consist of interests in
developed and undeveloped oil and gas leases and mineral acreage
located in our core operating areas. These interests entitle us
to drill for and produce oil, gas and NGLs from specific areas.
Our interests are mostly in the form of working interests and,
to a lesser extent, overriding royalty, mineral and net profits
interests, foreign government concessions and other forms of
direct and indirect ownership in oil and gas properties.
We also have certain midstream assets, including natural gas and
NGL processing plants and pipeline systems. Our most significant
midstream assets are our assets serving the Barnett Shale region
in north Texas. These assets include approximately
3,100 miles of pipeline, two natural gas processing plants
with 750 MMcf per day of total capacity, and a
15 MBbls per day NGL fractionator. To support our continued
development and growing production in the Woodford Shale,
located in southeastern Oklahoma, we constructed the Northridge
natural gas processing plant in 2008. The Northridge plant has a
capacity of 200 MMcf per day.
Our midstream assets also include the Access Pipeline
transportation system in Canada. This
220-mile
dual pipeline system extends from our Jackfish operations in
northern Alberta to a 350 MBbls storage terminal in
Edmonton. The dual pipeline system allows us to blend the
Jackfish heavy oil production with condensate and transport the
combined product to the Edmonton crude oil market for sale. We
have a 50% ownership interest in the Access Pipeline.
Proved
Reserves and Estimated Future Net Revenue
The SEC defines proved oil and gas reserves as the estimated
quantities of crude oil, gas and NGLs that geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions. Existing economic and
operating conditions is defined as those prices and costs as of
the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future
conditions.
The process of estimating oil, gas and NGL reserves is complex
and requires significant judgment as discussed in
Item 1A. Risk Factors. As a result, we have
developed internal policies for estimating and recording
reserves. Our policies regarding booking reserves require proved
reserves to be in compliance with the SEC definitions and
guidance. Our policies assign responsibilities for compliance in
reserves bookings to our Reserve Evaluation Group (the
Group) and require that reserve estimates be made by
qualified reserves estimators (QREs), as defined by
the Society of Petroleum Engineers standards. A list of
our QREs is kept by the Senior Advisor Corporate
Reserves. All QREs are required to receive education covering
the fundamentals of SEC proved reserves assignments.
The Group is responsible for the internal review and
certification of reserve estimates and includes the
Director Reserves and Economics and the Senior
Advisor Corporate Reserves. The Group reports
independently of any of our operating divisions. The Senior Vice
President Strategic Development is directly
responsible for overseeing the Group and reports to our
President. No portion of the Groups compensation is
directly dependent on the quantity of reserves booked.
Throughout the year, the Group performs internal audits of each
operating divisions reserves. Selection criteria of
reserves that are audited include major fields and major
additions and revisions to reserves. In addition, the Group
reviews reserve estimates with each of the third-party petroleum
consultants discussed below.
In addition to internal audits, we engage three independent
petroleum consulting firms to both prepare and audit a
significant portion of our proved reserves. Ryder Scott Company,
L.P. prepared the 2008 reserve estimates for all of our offshore
Gulf of Mexico properties and for 99% of our International
proved reserves. LaRoche Petroleum Consultants, Ltd. audited the
2008 reserve estimates for 90% of our domestic onshore
properties. AJM Petroleum Consultants audited 78% of our
Canadian reserves.
16
Set forth below is a summary of the reserves that were
evaluated, either by preparation or audit, by independent
petroleum consultants for each of the years ended 2008, 2007 and
2006.
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|
|
|
|
|
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|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Prepared
|
|
|
Audited
|
|
|
Prepared
|
|
|
Audited
|
|
|
Prepared
|
|
|
Audited
|
|
|
U.S.
|
|
|
5
|
%
|
|
|
87
|
%
|
|
|
6
|
%
|
|
|
83
|
%
|
|
|
7
|
%
|
|
|
81
|
%
|
Canada
|
|
|
|
|
|
|
78
|
%
|
|
|
34
|
%
|
|
|
51
|
%
|
|
|
46
|
%
|
|
|
39
|
%
|
International
|
|
|
99
|
%
|
|
|
|
|
|
|
99
|
%
|
|
|
|
|
|
|
99
|
%
|
|
|
|
|
Total
|
|
|
9
|
%
|
|
|
81
|
%
|
|
|
19
|
%
|
|
|
69
|
%
|
|
|
28
|
%
|
|
|
61
|
%
|
Prepared reserves are those quantities of reserves
that were prepared by an independent petroleum consultant.
Audited reserves are those quantities of reserves
that were estimated by our employees and audited by an
independent petroleum consultant. An audit is an examination of
a companys proved oil and gas reserves and net cash flow
by an independent petroleum consultant that is conducted for the
purpose of expressing an opinion as to whether such estimates,
in aggregate, are reasonable and have been estimated and
presented in conformity with generally accepted petroleum
engineering and evaluation principles.
In addition to conducting these internal and external reviews,
we also have a Reserves Committee which consists of three
independent members of our Board of Directors. Although we are
not required to have a Reserves Committee, we established ours
in 2004 to provide additional oversight of our reserves
estimation and certification process. The Reserves Committee was
designed to assist the Board of Directors with its duties and
responsibilities in evaluating and reporting our proved
reserves, much like our Audit Committee assists the Board of
Directors in supervising our audit and financial reporting
requirements. Besides being independent, the members of our
Reserves Committee also have educational backgrounds in geology
or petroleum engineering, as well as experience relevant to the
reserves estimation process.
The Reserves Committee meets at least twice a year to discuss
reserves issues and policies, and periodically meets separately
with our senior reserves engineering personnel and our
independent petroleum consultants. The responsibilities of the
Reserves Committee include the following:
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perform an annual review and evaluation of our consolidated oil,
gas and NGL reserves;
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verify the integrity of our reserves evaluation and reporting
system;
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evaluate, prepare and disclose our compliance with legal and
regulatory requirements related to our oil, gas and NGL reserves;
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investigate and verify the qualifications and independence of
our independent engineering consultants;
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monitor the performance of our independent engineering
consultants; and
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monitor and evaluate our business practices and ethical
standards in relation to the preparation and disclosure of
reserves.
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17
The following table sets forth our estimated proved reserves and
related estimated cash flow information as of December 31,
2008. These estimates correspond with the method used in
presenting the Supplemental Information on Oil and Gas
Operations in Note 20 to our consolidated financial
statements included herein.
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Total
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Proved
|
|
|
Proved
|
|
|
|
Proved
|
|
|
Developed
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Undeveloped
|
|
|
|
Reserves
|
|
|
Reserves
|
|
|
Reserves
|
|
|
Total Reserves
|
|
|
|
|
|
|
|
|
|
|
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Oil (MMBbls)
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|
|
429
|
|
|
|
301
|
|
|
|
128
|
|
Gas (Bcf)
|
|
|
9,885
|
|
|
|
8,044
|
|
|
|
1,841
|
|
NGLs (MMBbls)
|
|
|
352
|
|
|
|
292
|
|
|
|
60
|
|
MMBoe(1)
|
|
|
2,428
|
|
|
|
1,934
|
|
|
|
494
|
|
Pre-tax future net revenue (in millions)(2)
|
|
$
|
26,731
|
|
|
$
|
22,946
|
|
|
$
|
3,785
|
|
Pre-tax 10% present value (in millions)(2)
|
|
$
|
14,178
|
|
|
$
|
13,279
|
|
|
$
|
899
|
|
Standardized measure of discounted future net cash flows (in
millions)(2)(3)
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|
$
|
10,492
|
|
|
|
|
|
|
|
|
|
U.S. Reserves
|
|
|
|
|
|
|
|
|
|
|
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Oil (MMBbls)
|
|
|
167
|
|
|
|
133
|
|
|
|
34
|
|
Gas (Bcf)
|
|
|
8,369
|
|
|
|
6,681
|
|
|
|
1,688
|
|
NGLs (MMBbls)
|
|
|
317
|
|
|
|
261
|
|
|
|
56
|
|
MMBoe(1)
|
|
|
1,878
|
|
|
|
1,508
|
|
|
|
370
|
|
Pre-tax future net revenue (in millions)(2)
|
|
$
|
20,284
|
|
|
$
|
17,916
|
|
|
$
|
2,368
|
|
Pre-tax 10% present value (in millions)(2)
|
|
$
|
10,185
|
|
|
$
|
9,945
|
|
|
$
|
240
|
|
Standardized measure of discounted future net cash flows (in
millions)(2)(3)
|
|
$
|
7,381
|
|
|
|
|
|
|
|
|
|
Canadian Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
134
|
|
|
|
110
|
|
|
|
24
|
|
Gas (Bcf)
|
|
|
1,510
|
|
|
|
1,357
|
|
|
|
153
|
|
NGLs (MMBbls)
|
|
|
35
|
|
|
|
31
|
|
|
|
4
|
|
MMBoe(1)
|
|
|
421
|
|
|
|
367
|
|
|
|
54
|
|
Pre-tax future net revenue (in millions)(2)
|
|
$
|
4,852
|
|
|
$
|
4,569
|
|
|
$
|
283
|
|
Pre-tax 10% present value (in millions)(2)
|
|
$
|
2,959
|
|
|
$
|
2,931
|
|
|
$
|
28
|
|
Standardized measure of discounted future net cash flows (in
millions)(2)(3)
|
|
$
|
2,252
|
|
|
|
|
|
|
|
|
|
International Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
128
|
|
|
|
58
|
|
|
|
70
|
|
Gas (Bcf)
|
|
|
6
|
|
|
|
6
|
|
|
|
|
|
NGLs (MMBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
MMBoe(1)
|
|
|
129
|
|
|
|
59
|
|
|
|
70
|
|
Pre-tax future net revenue (in millions)(2)
|
|
$
|
1,595
|
|
|
$
|
461
|
|
|
$
|
1,134
|
|
Pre-tax 10% present value (in millions)(2)
|
|
$
|
1,034
|
|
|
$
|
403
|
|
|
$
|
631
|
|
Standardized measure of discounted future net cash flows (in
millions)(2)(3)
|
|
$
|
859
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gas reserves are converted to Boe at the rate of six Mcf per Bbl
of oil, based upon the approximate relative energy content of
gas and oil, which rate is not necessarily indicative of the
relationship of gas and oil prices. NGL reserves are converted
to Boe on a one-to-one basis with oil. |
|
(2) |
|
Estimated pre-tax future net revenue represents estimated future
revenue to be generated from the production of proved reserves,
net of estimated production and development costs and site
restoration and |
18
|
|
|
|
|
abandonment charges. The amounts shown do not give effect to
depreciation, depletion and amortization, or to non-property
related expenses such as debt service and income tax expense. |
|
|
|
These amounts were calculated using prices and costs in effect
for each individual property as of December 31, 2008. These
prices were not changed except where different prices were fixed
and determinable from applicable contracts. These assumptions
yielded average prices over the life of our properties of $32.65
per Bbl of oil, $4.75 per Mcf of gas and $16.54 per Bbl of NGLs.
These prices compare to the December 31, 2008, NYMEX cash
price of $44.60 per Bbl for crude oil and the Henry Hub spot
price of $5.71 per MMBtu for gas. |
|
|
|
The present value of after-tax future net revenues discounted at
10% per annum (standardized measure) was
$10.5 billion at the end of 2008. Included as part of
standardized measure were discounted future income taxes of
$3.7 billion. Excluding these taxes, the present value of
our pre-tax future net revenue (pre-tax 10% present
value) was $14.2 billion. We believe the pre-tax 10%
present value is a useful measure in addition to the after-tax
standardized measure. The pre-tax 10% present value assists in
both the determination of future cash flows of the current
reserves as well as in making relative value comparisons among
peer companies. The after-tax standardized measure is dependent
on the unique tax situation of each individual company, while
the pre-tax 10% present value is based on prices and discount
factors, which are more consistent from company to company. We
also understand that securities analysts use the pre-tax 10%
present value measure in similar ways. |
|
(3) |
|
See Note 20 to the consolidated financial statements
included in Item 8. Financial Statements and
Supplementary Data. |
19
As presented in the previous table, we had 1,934 MMBoe of
proved developed reserves at December 31, 2008. Proved
developed reserves consist of proved developed producing
reserves and proved developed non-producing reserves. The
following table provides additional information regarding our
proved developed reserves at December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
Proved
|
|
|
Proved
|
|
|
|
Proved
|
|
|
Developed
|
|
|
Developed
|
|
|
|
Developed
|
|
|
Producing
|
|
|
Non-Producing
|
|
|
|
Reserves
|
|
|
Reserves
|
|
|
Reserves
|
|
|
Total Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
301
|
|
|
|
250
|
|
|
|
51
|
|
Gas (Bcf)
|
|
|
8,044
|
|
|
|
7,051
|
|
|
|
993
|
|
NGLs (MMBbls)
|
|
|
292
|
|
|
|
259
|
|
|
|
33
|
|
MMBoe
|
|
|
1,934
|
|
|
|
1,684
|
|
|
|
250
|
|
U.S. Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
133
|
|
|
|
112
|
|
|
|
21
|
|
Gas (Bcf)
|
|
|
6,681
|
|
|
|
5,851
|
|
|
|
830
|
|
NGLs (MMBbls)
|
|
|
261
|
|
|
|
230
|
|
|
|
31
|
|
MMBoe
|
|
|
1,508
|
|
|
|
1,317
|
|
|
|
191
|
|
Canadian Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
110
|
|
|
|
91
|
|
|
|
19
|
|
Gas (Bcf)
|
|
|
1,357
|
|
|
|
1,194
|
|
|
|
163
|
|
NGLs (MMBbls)
|
|
|
31
|
|
|
|
29
|
|
|
|
2
|
|
MMBoe
|
|
|
367
|
|
|
|
319
|
|
|
|
48
|
|
International Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
58
|
|
|
|
47
|
|
|
|
11
|
|
Gas (Bcf)
|
|
|
6
|
|
|
|
6
|
|
|
|
|
|
NGLs (MMBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
MMBoe
|
|
|
59
|
|
|
|
48
|
|
|
|
11
|
|
No estimates of our proved reserves have been filed with or
included in reports to any federal or foreign governmental
authority or agency since the beginning of 2008 except in
filings with the SEC and the Department of Energy
(DOE). Reserve estimates filed with the SEC
correspond with the estimates of our reserves contained herein.
Reserve estimates filed with the DOE are based upon the same
underlying technical and economic assumptions as the estimates
of our reserves included herein. However, the DOE requires
reports to include the interests of all owners in wells that we
operate and to exclude all interests in wells that we do not
operate.
The prices used in calculating the estimated future net revenues
attributable to proved reserves do not necessarily reflect
market prices for oil, gas and NGL production subsequent to
December 31, 2008. There can be no assurance that all of
the proved reserves will be produced and sold within the periods
indicated, that the assumed prices will be realized or that
existing contracts will be honored or judicially enforced.
Production,
Revenue and Price History
Certain information concerning oil, gas and NGL production,
prices, revenues (net of all royalties, overriding royalties and
other third-party interests) and operating expenses for the
three years ended December 31, 2008, is set forth in
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations.
20
Drilling
Activities
The following tables summarize the results of our development
and exploratory drilling activity for the past three years. The
tables do not include our Egyptian or West African operations
that were discontinued in 2006 and 2007, respectively.
Development
Well Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells Drilling at
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Net Wells Completed(2)
|
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Productive
|
|
|
Dry
|
|
|
Productive
|
|
|
Dry
|
|
|
Productive
|
|
|
Dry
|
|
|
U.S.
|
|
|
111
|
|
|
|
73.2
|
|
|
|
1,033.0
|
|
|
|
18.5
|
|
|
|
978.2
|
|
|
|
21.1
|
|
|
|
877.1
|
|
|
|
12.5
|
|
Canada
|
|
|
6
|
|
|
|
4.3
|
|
|
|
528.9
|
|
|
|
3.2
|
|
|
|
531.2
|
|
|
|
|
|
|
|
593.2
|
|
|
|
3.3
|
|
International
|
|
|
9
|
|
|
|
1.0
|
|
|
|
13.8
|
|
|
|
1.4
|
|
|
|
9.2
|
|
|
|
|
|
|
|
6.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
126
|
|
|
|
78.5
|
|
|
|
1,575.7
|
|
|
|
23.1
|
|
|
|
1,518.6
|
|
|
|
21.1
|
|
|
|
1,476.4
|
|
|
|
15.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
Well Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells Drilling at
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Net Wells Completed(2)
|
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Productive
|
|
|
Dry
|
|
|
Productive
|
|
|
Dry
|
|
|
Productive
|
|
|
Dry
|
|
|
U.S.
|
|
|
13
|
|
|
|
9.8
|
|
|
|
13.6
|
|
|
|
3.8
|
|
|
|
11.6
|
|
|
|
4.2
|
|
|
|
24.5
|
|
|
|
10.3
|
|
Canada
|
|
|
7
|
|
|
|
4.0
|
|
|
|
50.1
|
|
|
|
3.3
|
|
|
|
83.3
|
|
|
|
1.5
|
|
|
|
82.1
|
|
|
|
1.0
|
|
International
|
|
|
1
|
|
|
|
0.2
|
|
|
|
|
|
|
|
5.6
|
|
|
|
|
|
|
|
0.6
|
|
|
|
|
|
|
|
1.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21
|
|
|
|
14.0
|
|
|
|
63.7
|
|
|
|
12.7
|
|
|
|
94.9
|
|
|
|
6.3
|
|
|
|
106.6
|
|
|
|
13.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gross wells are the sum of all wells in which we own an interest. |
|
(2) |
|
Net wells are gross wells multiplied by our fractional working
interests therein. |
For the wells being drilled as of December 31, 2008
presented in the tables above, the following table summarizes
the results of such wells as of February 1, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
Dry
|
|
|
Still In Progress
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
U.S.
|
|
|
25
|
|
|
|
18.3
|
|
|
|
2
|
|
|
|
1.5
|
|
|
|
97
|
|
|
|
63.1
|
|
Canada
|
|
|
11
|
|
|
|
7.5
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
0.8
|
|
International
|
|
|
3
|
|
|
|
0.7
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
0.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
39
|
|
|
|
26.5
|
|
|
|
2
|
|
|
|
1.5
|
|
|
|
106
|
|
|
|
64.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
Well
Statistics
The following table sets forth our producing wells as of
December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Wells
|
|
|
Gas Wells
|
|
|
Total Wells
|
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
U.S. Onshore
|
|
|
8,265
|
|
|
|
2,850
|
|
|
|
19,166
|
|
|
|
13,075
|
|
|
|
27,431
|
|
|
|
15,925
|
|
U.S. Offshore
|
|
|
444
|
|
|
|
309
|
|
|
|
218
|
|
|
|
142
|
|
|
|
662
|
|
|
|
451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
8,709
|
|
|
|
3,159
|
|
|
|
19,384
|
|
|
|
13,217
|
|
|
|
28,093
|
|
|
|
16,376
|
|
Canada
|
|
|
3,675
|
|
|
|
2,704
|
|
|
|
4,928
|
|
|
|
2,847
|
|
|
|
8,603
|
|
|
|
5,551
|
|
International
|
|
|
479
|
|
|
|
206
|
|
|
|
|
|
|
|
|
|
|
|
479
|
|
|
|
206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grand Total
|
|
|
12,863
|
|
|
|
6,069
|
|
|
|
24,312
|
|
|
|
16,064
|
|
|
|
37,175
|
|
|
|
22,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gross wells are the total number of wells in which we own a
working interest. |
|
(2) |
|
Net wells are gross wells multiplied by our fractional working
interests therein. |
Developed
and Undeveloped Acreage
The following table sets forth our developed and undeveloped oil
and gas lease and mineral acreage as of December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
|
(In thousands)
|
|
|
U.S. Onshore
|
|
|
3,425
|
|
|
|
2,298
|
|
|
|
6,444
|
|
|
|
3,565
|
|
U.S. Offshore
|
|
|
337
|
|
|
|
187
|
|
|
|
2,228
|
|
|
|
1,277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
3,762
|
|
|
|
2,485
|
|
|
|
8,672
|
|
|
|
4,842
|
|
Canada
|
|
|
3,633
|
|
|
|
2,265
|
|
|
|
8,251
|
|
|
|
5,436
|
|
International
|
|
|
198
|
|
|
|
53
|
|
|
|
10,654
|
|
|
|
9,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grand Total
|
|
|
7,593
|
|
|
|
4,803
|
|
|
|
27,577
|
|
|
|
19,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gross acres are the total number of acres in which we own a
working interest. |
|
(2) |
|
Net acres are gross acres multiplied by our fractional working
interests therein. |
Operation
of Properties
The day-to-day operations of oil and gas properties are the
responsibility of an operator designated under pooling or
operating agreements. The operator supervises production,
maintains production records, employs field personnel and
performs other functions.
We are the operator of 22,527 of our wells. As operator, we
receive reimbursement for direct expenses incurred in the
performance of our duties as well as monthly per-well producing
and drilling overhead reimbursement at rates customarily charged
in the area. In presenting our financial data, we record the
monthly overhead reimbursements as a reduction of general and
administrative expense, which is a common industry practice.
Organization
Structure and Property Profiles
Our properties are located within the U.S. onshore and
offshore regions, Canada, and certain locations outside North
America. The following table presents proved reserve information
for our significant properties as of December 31, 2008,
along with their production volumes for the year 2008.
Additional summary profile information for our significant
properties is provided following the table.
We have certain North American onshore and offshore properties
we consider to be significant because they may be the source of
significant future growth in proved reserves and production.
However, these
22
properties are not included in the following table because as of
December 31, 2008, such properties had only minimal, if
any, proved reserves or production. Onshore, these properties
include the Haynesville, Cana and Cody properties in the
U.S. and the Horn River Basin properties in Canada.
Offshore, these properties include our deepwater development and
exploration properties in the Gulf of Mexico. These properties
and our related development plans are discussed along with our
other significant properties following the table.
Also, as presented in the table, we had no proved reserves
associated with our Jackfish operations as of December 31,
2008. During 2008 and thus far in 2009, we have been producing
heavy oil from our Jackfish property. However, due to low crude
oil prices and unfavorable operating conditions as of
December 31, 2008, our Jackfish reserves did not meet the
existing economic and operating condition requirement to be
classified as proved at the end of 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
Proved
|
|
|
|
|
|
|
|
|
|
Reserves
|
|
|
Reserves
|
|
|
Production
|
|
|
Production
|
|
|
|
(MMBoe)(1)
|
|
|
%(2)
|
|
|
(MMBoe)(1)
|
|
|
%(2)
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
|
894
|
|
|
|
36.8
|
%
|
|
|
66
|
|
|
|
27.9
|
%
|
Carthage
|
|
|
209
|
|
|
|
8.6
|
%
|
|
|
17
|
|
|
|
7.2
|
%
|
Permian Basin, Texas
|
|
|
125
|
|
|
|
5.1
|
%
|
|
|
9
|
|
|
|
3.6
|
%
|
Washakie
|
|
|
105
|
|
|
|
4.3
|
%
|
|
|
7
|
|
|
|
2.8
|
%
|
Groesbeck
|
|
|
62
|
|
|
|
2.5
|
%
|
|
|
7
|
|
|
|
3.1
|
%
|
Woodford Shale
|
|
|
48
|
|
|
|
2.0
|
%
|
|
|
4
|
|
|
|
1.5
|
%
|
Other U.S Onshore
|
|
|
334
|
|
|
|
13.8
|
%
|
|
|
36
|
|
|
|
15.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S Onshore
|
|
|
1,777
|
|
|
|
73.1
|
%
|
|
|
146
|
|
|
|
61.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deepwater Producing
|
|
|
56
|
|
|
|
2.3
|
%
|
|
|
7
|
|
|
|
3.1
|
%
|
Other U.S Offshore
|
|
|
45
|
|
|
|
1.9
|
%
|
|
|
9
|
|
|
|
3.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S Offshore
|
|
|
101
|
|
|
|
4.2
|
%
|
|
|
16
|
|
|
|
6.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S
|
|
|
1,878
|
|
|
|
77.3
|
%
|
|
|
162
|
|
|
|
68.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lloydminster
|
|
|
92
|
|
|
|
3.8
|
%
|
|
|
16
|
|
|
|
6.6
|
%
|
Peace River Arch
|
|
|
82
|
|
|
|
3.4
|
%
|
|
|
8
|
|
|
|
3.5
|
%
|
Deep Basin
|
|
|
66
|
|
|
|
2.8
|
%
|
|
|
10
|
|
|
|
4.2
|
%
|
Northeast British Columbia
|
|
|
64
|
|
|
|
2.6
|
%
|
|
|
9
|
|
|
|
3.6
|
%
|
Jackfish
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
1.5
|
%
|
Other Canada
|
|
|
117
|
|
|
|
4.8
|
%
|
|
|
14
|
|
|
|
6.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Canada
|
|
|
421
|
|
|
|
17.4
|
%
|
|
|
61
|
|
|
|
25.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Azerbaijan
|
|
|
85
|
|
|
|
3.5
|
%
|
|
|
6
|
|
|
|
2.6
|
%
|
China
|
|
|
18
|
|
|
|
0.8
|
%
|
|
|
5
|
|
|
|
2.1
|
%
|
Brazil
|
|
|
4
|
|
|
|
0.1
|
%
|
|
|
2
|
|
|
|
0.6
|
%
|
Other
|
|
|
22
|
|
|
|
0.9
|
%
|
|
|
2
|
|
|
|
0.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
129
|
|
|
|
5.3
|
%
|
|
|
15
|
|
|
|
6.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grand Total
|
|
|
2,428
|
|
|
|
100.0
|
%
|
|
|
238
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gas reserves and production are converted to Boe at the rate of
six Mcf of gas per Bbl of oil, based upon the approximate
relative energy content of gas and oil, which rate is not
necessarily indicative of the |
23
|
|
|
|
|
relationship of gas and oil prices. NGL reserves and production
are converted to Boe on a one-to-one basis with oil. |
|
(2) |
|
Percentage of proved reserves and production the property bears
to total proved reserves and production based on actual figures
and not the rounded figures included in this table. |
U.S.
Onshore
Barnett Shale The Barnett Shale, located in
north Texas, is our largest property both in terms of production
and proved reserves. Our leases include approximately
715,000 net acres located primarily in Denton, Johnson,
Parker, Tarrant and Wise counties. The Barnett Shale is a
non-conventional reservoir and it produces natural gas and NGLs.
We have an average working interest of greater than 90%. We
drilled 659 gross wells in 2008.
Carthage The Carthage area in east Texas
includes primarily Harrison, Marion, Panola and Shelby counties.
Our average working interest is about 85% and we hold
approximately 173,000 net acres. Our Carthage area wells
produce primarily natural gas and NGLs from conventional
reservoirs. We drilled 132 gross wells in 2008.
Permian Basin, Texas Our oil and gas
properties in the Permian Basin of west Texas comprise
approximately 470,000 net acres located primarily in
Andrews, Crane, Ector, Martin, Terry, Ward and Yoakum counties.
These properties produce both oil and gas from conventional
reservoirs. Our average working interest in these properties is
about 40%. We drilled 71 gross wells in 2008.
Washakie Our Washakie area leases are
concentrated in Carbon and Sweetwater counties in southern
Wyoming. Our average working interest is about 76% and we hold
about 157,000 net acres in the area. The Washakie wells
produce primarily natural gas from conventional reservoirs. In
2008, we drilled 115 gross wells.
Groesbeck The Groesbeck area of east Texas
includes portions of Freestone, Leon, Limestone and Robertson
counties. Our average working interest is approximately 72% and
we hold about 168,000 net acres of land. The Groesbeck
wells produce primarily natural gas from conventional
reservoirs. In 2008, we drilled 16 gross wells.
Woodford Shale Our Woodford Shale properties
in southeastern Oklahoma produce natural gas and NGLs from a
non-conventional reservoir. Our 54,000 net acres are
concentrated in Coal and Hughes counties and have an average
working interest of about 57%. In 2008, we drilled
131 gross wells in this area. To support our production in
the Woodford Shale, we also brought online a 200 MMcf per
day natural gas processing plant in 2008.
2009 Development Plans We expect 2009 oil,
gas and NGL prices will be noticeably lower than those for 2008.
As a result, we expect our operating cash flow will also be
lower than that for 2008 and will require us to scale back our
anticipated capital expenditures in 2009 compared to 2008.
Accordingly, we expect to drill fewer wells in 2009 than in 2008
for the key U.S. Onshore areas discussed above.
Our reduction in 2009 drilling activities in these areas is also
related to our plan to devote a portion of our planned 2009
capital expenditures to develop three new unconventional natural
gas plays. In 2008, we built a position of nearly
1.3 million net acres in these unconventional natural gas
plays. In east Texas and north Louisiana we have accumulated
approximately 570,000 net acres prospective for the
Haynesville shale formation. In western Oklahoma, our Cana
leasehold position targets the deep Woodford shale formation in
the Anadarko Basin. We hold about 112,000 net acres in the
Cana area. In south central Montana, we have accumulated a
significant leasehold position for our Cody project area. We
hold approximately 575,000 net acres in this region. In
2009, we will continue to evaluate our acreage and drill wells
in these emerging plays to assess the reserve and production
potential of our acreage position.
24
U.S.
Offshore
Deepwater Producing Our assets in the Gulf of
Mexico include three significant producing
properties Magnolia, Merganser and
Nansen located in deep water (greater than
600 feet). We have a 50% working interest in Merganser and
Nansen and a 25% working interest in Magnolia. The three fields
are located on federal leases and total approximately
23,000 net acres. The properties produce both oil and gas.
Deepwater Development In addition to our
three significant deepwater producing properties, we will
continue development activities on our deepwater Cascade project
throughout 2009. Cascade was discovered in 2002 and is located
on federal leases encompassing approximately 12,000 net
acres. We have a 50% working interest in Cascade. Production
from Cascade, which will be primarily oil, is expected to begin
in 2010. Cascade will be the first project in the Gulf to
utilize an FPSO.
Deepwater Exploration Our exploration program
in the Gulf of Mexico is focused primarily on deepwater
opportunities. Our deepwater exploratory prospects include
Miocene-aged objectives (five million to 24 million years)
and older and deeper Lower Tertiary objectives. We hold federal
leases comprising approximately one million net acres in our
deepwater exploration inventory.
In 2006, a successful production test of the Jack
No. 2 well provided evidence that our Lower Tertiary
properties may be a source of meaningful future reserve and
production growth. Through 2008, we have drilled four discovery
wells in the Lower Tertiary. These include Cascade in 2002 (see
Deepwater Development above), St. Malo in 2003, Jack
in 2004 and Kaskida in 2006. We currently hold 161 blocks in the
Lower Tertiary and we have identified 21 additional prospects to
date.
At St. Malo, in which our working interest is 25%, we drilled
two delineation wells in 2008. At Jack, where our working
interest is 25%, we drilled a second appraisal well in 2008. A
sidetrack appraisal well was drilled on the Kaskida unit in 2008
and we commenced an additional delineation well in late 2008.
Our working interest in Kaskida is 30%, and we believe Kaskida
is the largest of our four Lower Tertiary discoveries to date.
Also in 2008, we participated in a sidetrack delineation well on
the Miocene-aged Mission Deep discovery in which we have a 50%
working interest. We have identified 14 additional prospects in
our deepwater Miocene inventory to date.
In total, we drilled seven exploratory and appraisal wells in
the deepwater Gulf of Mexico in 2008. Our working interests in
these exploratory opportunities range from 25% to 50%. In 2009,
we will continue to perform additional delineation drilling and
continue to plan the development of Jack and St. Malo.
Canada
Lloydminster Our Lloydminster properties are
located to the south and east of Jackfish in eastern Alberta and
western Saskatchewan. Lloydminster produces heavy oil by
conventional means without steam injection. We hold
2.5 million net acres and have an 89% average working
interest in our Lloydminster properties. In 2008, we drilled
425 gross wells in the area.
Peace River Arch The Peace River Arch is
located in west central Alberta. We hold approximately
569,000 net acres in the area, which produces primarily
natural gas and NGLs from conventional reservoirs. Our average
working interest in the area is approximately 70%. We drilled
66 gross wells in the Peace River Arch in 2008.
Deep Basin Our properties in Canadas
Deep Basin include portions of west central Alberta and east
central British Columbia. We hold approximately 602,000 net
acres in the Deep Basin. The area produces primarily natural gas
and natural gas liquids from conventional reservoirs. Our
average working interest in the Deep Basin is 45%. In 2008, we
drilled 61 gross wells.
Northeast British Columbia Our northeast
British Columbia properties are located primarily in British
Columbia and to a lesser extent in northwestern Alberta. We hold
approximately 1.7 million net acres in the
25
area. These properties produce principally natural gas from
conventional reservoirs. We hold a 76% average working interest
in these properties. We drilled 37 gross wells in the area
in 2008.
Jackfish By the end of 2008, we ramped up
production from our 100%-owned Jackfish thermal heavy oil
project in the non-conventional oil sands of east central
Alberta to 22,000 Bbls per day. We are employing
steam-assisted gravity drainage at Jackfish. Production is
expected to increase in 2009 to its peak production target of
35,000 Bbls per day. We hold approximately 75,000 net
acres in the entire Jackfish area, which can support expansion
of the original project. In 2008, we received regulatory
approval to develop a second phase of Jackfish. Like the first
phase, this second phase of Jackfish is also expected to
eventually produce 35,000 Bbls per day of heavy oil
production.
2009 Development Plans Similar to our 2009
plans for our U.S. Onshore areas discussed above, we expect
to drill fewer wells in 2009 than in 2008 for the key areas in
Canada discussed above. Our plans to drill fewer wells in these
areas is also affected by our intentions to devote a portion of
our planned 2009 capital expenditures to develop our positions
in the Horn River Basin in northeast British Columbia. In 2008,
we accumulated approximately 153,000 net acres targeting
the Devonian shale in this area. In 2009, we will continue to
evaluate our acreage and drill wells in this area to assess the
reserve and production potential of our acreage position.
International
Azerbaijan Outside North America,
Devons largest international property in terms of proved
reserves is the Azeri-Chirag-Gunashli (ACG) oil
field located offshore Azerbaijan in the Caspian Sea. ACG
produces crude oil from conventional reservoirs. We hold
approximately 6,000 net acres in the ACG field and have a
5.6% working interest. In 2008, we participated in drilling
15 gross wells.
China Our production in China is from the
Panyu development in the Pearl River Mouth Basin in the South
China Sea. The Panyu fields produce oil from conventional
reservoirs. In addition to Panyu, which is located on
Block 15/34, we hold leases in four exploratory blocks
offshore China. In total, we have 7.9 million net acres
under lease in China. We have a 24.5% working interest at Panyu
and 100% working interests in the exploratory blocks. We drilled
seven gross wells in China in 2008.
Brazil In 2008, we continued to ramp up
production from our Polvo development, which we operate with a
60% working interest. Polvo is located offshore in the Campos
Basin in Block BM-C-8. We experienced mechanical issues during
2008 at Polvo that delayed bringing a portion of our expected
production online. As of December 31, 2008, the mechanical
issues appear to have been corrected, and we exited the year
with gross production at approximately 17,000 Bbls per day.
In addition to our development project at Polvo, we hold acreage
in eight exploratory blocks. In aggregate, we have
1.4 million net acres in Brazil. Our working interests
range from 18% to 100% in these blocks. We drilled 12 gross
wells in Brazil in 2008 and over the next two years we plan to
drill up to eight exploratory wells.
Title to
Properties
Title to properties is subject to contractual arrangements
customary in the oil and gas industry, liens for current taxes
not yet due and, in some instances, other encumbrances. We
believe that such burdens do not materially detract from the
value of such properties or from the respective interests
therein or materially interfere with their use in the operation
of the business.
As is customary in the industry, other than a preliminary review
of local records, little investigation of record title is made
at the time of acquisitions of undeveloped properties.
Investigations, which generally include a title opinion of
outside counsel, are made prior to the consummation of an
acquisition of producing properties and before commencement of
drilling operations on undeveloped properties.
26
|
|
Item 3.
|
Legal
Proceedings
|
Royalty
Matters
Numerous natural gas producers and related parties, including
Devon, have been named in various lawsuits alleging violation of
the federal False Claims Act. The suits allege that the
producers and related parties used below-market prices, improper
deductions, improper measurement techniques and transactions
with affiliates, which resulted in underpayment of royalties in
connection with natural gas and NGLs produced and sold from
federal and Indian owned or controlled lands. The principal suit
in which Devon is a defendant is United States ex rel.
Wright v. Chevron USA, Inc. et al. (the Wright
case). The suit was originally filed in August 1996 in the
United States District Court for the Eastern District of Texas,
but was consolidated in October 2000 with other suits for
pre-trial proceedings in the United States District Court for
the District of Wyoming. On July 10, 2003, the District of
Wyoming remanded the Wright case back to the Eastern District of
Texas to resume proceedings. On April 12, 2007, the court
entered a trial plan and scheduling order in which the case will
proceed in phases. Two phases have been scheduled to date. The
first phase was scheduled to begin in August 2008, but the
defendant settled prior to trial. The second phase was scheduled
to begin in February 2009, but the defendants settled prior to
trial. Devon was not included in the groups of defendants
selected for these first two phases. Devon believes that it has
acted reasonably, has legitimate and strong defenses to all
allegations in the suit, and has paid royalties in good faith.
Devon does not currently believe that it is subject to material
exposure with respect to this lawsuit and, therefore, no
liability related to this lawsuit has been recorded.
Other
Matters
We are involved in other various routine legal proceedings
incidental to our business. However, to our knowledge as of the
date of this report, there were no other material pending legal
proceedings to which we are a party or to which any of our
property is subject.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
There were no matters submitted to a vote of security holders
during the fourth quarter of 2008.
27
PART II
|
|
Item 5.
|
Market
for Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
|
Our common stock is traded on the New York Stock Exchange (the
NYSE). On February 16, 2009, there were 14,074
holders of record of our common stock. The following table sets
forth the quarterly high and low sales prices for our common
stock as reported by the NYSE during 2008 and 2007. Also,
included are the quarterly dividends per share paid during 2008
and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Range of Common
|
|
|
|
|
|
|
Stock
|
|
|
Dividends
|
|
|
|
High
|
|
|
Low
|
|
|
Per Share
|
|
|
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended March 31, 2008
|
|
$
|
108.13
|
|
|
$
|
74.56
|
|
|
$
|
0.1600
|
|
Quarter Ended June 30, 2008
|
|
$
|
127.16
|
|
|
$
|
101.31
|
|
|
$
|
0.1600
|
|
Quarter Ended September 30, 2008
|
|
$
|
127.43
|
|
|
$
|
82.10
|
|
|
$
|
0.1600
|
|
Quarter Ended December 31, 2008
|
|
$
|
91.69
|
|
|
$
|
54.40
|
|
|
$
|
0.1600
|
|
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended March 31, 2007
|
|
$
|
71.24
|
|
|
$
|
62.80
|
|
|
$
|
0.1400
|
|
Quarter Ended June 30, 2007
|
|
$
|
83.92
|
|
|
$
|
69.30
|
|
|
$
|
0.1400
|
|
Quarter Ended September 30, 2007
|
|
$
|
85.20
|
|
|
$
|
69.01
|
|
|
$
|
0.1400
|
|
Quarter Ended December 31, 2007
|
|
$
|
94.75
|
|
|
$
|
80.05
|
|
|
$
|
0.1400
|
|
We began paying regular quarterly cash dividends on our common
stock in the second quarter of 1993. We anticipate continuing to
pay regular quarterly dividends in the foreseeable future.
Issuer
Purchases of Equity Securities
Our Board of Directors has approved a program to repurchase up
to 50 million shares, which expires on December 31,
2009. As of December 31, 2008, up to 45.5 million
shares can be repurchased under the 50 million share
repurchase program.
Our Board of Directors has also approved an ongoing, annual
stock repurchase program to minimize dilution resulting from
restricted stock issued to, and options exercised by, employees.
In 2008, the repurchase program authorized the repurchase of up
to 4.8 million shares or a cost of $422 million,
whichever amount was reached first. When the 2008 portion of
this annual program expired on December 31, 2008,
2.0 million shares had been repurchased under this program
for $178 million, or $87.83 per share.
No shares were repurchased under these programs during the
fourth quarter of 2008.
Prior to the end of 2008, our Board of Directors authorized the
2009 portion of the annual program. Under this program in 2009,
we are authorized to repurchase up to 4.8 million shares or
a cost of $360 million, whichever amount is reached first.
As of December 31, 2008, we are authorized to repurchase up
to 50.3 million shares under publicly announced programs.
This amount is comprised of the 45.5 million remaining
shares authorized to be repurchased under the 50 million
share repurchase program and the 4.8 million shares
authorized to be repurchased under the annual repurchase program
in 2009. However, in response to the current economic
environment and recent downturn in commodity prices, we have
indefinitely suspended activity under both these programs. As a
result, we do not anticipate repurchasing shares under these
programs in the foreseeable future. Should economic conditions
or commodity prices strengthen, we will consider resumption of
share repurchases under our authorized programs.
New York
Stock Exchange Certifications
This
Form 10-K
includes as exhibits the certifications of our Chief Executive
Officer and Chief Financial Officer, or persons performing
similar functions, required to be filed with the SEC pursuant to
Section 302 of the Sarbanes Oxley Act of 2002. We have also
filed with the New York Stock Exchange the 2008 annual
certification of our Chief Executive Officer confirming that we
have complied with the New York Stock Exchange corporate
governance listing standards.
28
Performance
Graph
The following performance graph compares the yearly percentage
change in the cumulative total shareholder return on
Devons common stock with the cumulative total returns of
the Standard & Poors 500 index (the
S&P 500 Index) and the group of companies included in
the Crude Petroleum and Natural Gas Standard Industrial
Classification code (the SIC Code). The graph was
prepared based on the following assumptions:
|
|
|
|
|
$100 was invested on December 31, 2003 in Devons
common stock, the S&P 500 Index and the SIC Code, and
|
|
|
|
Dividends have been reinvested subsequent to the initial
investment.
|
Comparison
of 5-Year
Cumulative Total Return
Devon, S&P 500 Index and SIC Code
The graph and related information shall not be deemed
soliciting material or to be filed with
the SEC, nor shall such information be incorporated by reference
into any future filing under the Securities Act of 1933, as
amended, or Securities Exchange Act of 1934, as amended, except
to the extent that we specifically incorporate such information
by reference into such a filing. The graph and information is
included for historical comparative purposes only and should not
be considered indicative of future stock performance.
29
|
|
Item 6.
|
Selected
Financial Data
|
The following selected financial information (not covered by the
report of independent registered public accounting firm) should
be read in conjunction with Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations, and the consolidated financial statements and
the notes thereto included in Item 8. Financial
Statements and Supplementary Data.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In millions, except per share data, ratios, prices and per
Boe amounts)
|
|
|
Operating Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
15,211
|
|
|
$
|
11,362
|
|
|
$
|
9,767
|
|
|
$
|
10,027
|
|
|
$
|
8,549
|
|
Total expenses and other income, net(1)
|
|
|
19,244
|
|
|
|
7,138
|
|
|
|
6,197
|
|
|
|
5,649
|
|
|
|
5,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations before income taxes
|
|
|
(4,033
|
)
|
|
|
4,224
|
|
|
|
3,570
|
|
|
|
4,378
|
|
|
|
3,059
|
|
Total income tax (benefit) expense
|
|
|
(954
|
)
|
|
|
1,078
|
|
|
|
936
|
|
|
|
1,481
|
|
|
|
970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
|
(3,079
|
)
|
|
|
3,146
|
|
|
|
2,634
|
|
|
|
2,897
|
|
|
|
2,089
|
|
Earnings from discontinued operations
|
|
|
931
|
|
|
|
460
|
|
|
|
212
|
|
|
|
33
|
|
|
|
97
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(2,148
|
)
|
|
$
|
3,606
|
|
|
$
|
2,846
|
|
|
$
|
2,930
|
|
|
$
|
2,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings applicable to common stockholders
|
|
$
|
(2,153
|
)
|
|
$
|
3,596
|
|
|
$
|
2,836
|
|
|
$
|
2,920
|
|
|
$
|
2,176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
$
|
(6.95
|
)
|
|
$
|
7.05
|
|
|
$
|
5.94
|
|
|
$
|
6.31
|
|
|
$
|
4.31
|
|
Earnings from discontinued operations
|
|
|
2.10
|
|
|
|
1.03
|
|
|
|
0.48
|
|
|
|
0.07
|
|
|
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(4.85
|
)
|
|
$
|
8.08
|
|
|
$
|
6.42
|
|
|
$
|
6.38
|
|
|
$
|
4.51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net (loss) earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
$
|
(6.95
|
)
|
|
$
|
6.97
|
|
|
$
|
5.87
|
|
|
$
|
6.19
|
|
|
$
|
4.19
|
|
Earnings from discontinued operations
|
|
|
2.10
|
|
|
|
1.03
|
|
|
|
0.47
|
|
|
|
0.07
|
|
|
|
0.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(4.85
|
)
|
|
$
|
8.00
|
|
|
$
|
6.34
|
|
|
$
|
6.26
|
|
|
$
|
4.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per common share
|
|
$
|
0.64
|
|
|
$
|
0.56
|
|
|
$
|
0.45
|
|
|
$
|
0.30
|
|
|
$
|
0.20
|
|
Weighted average common shares outstanding basic
|
|
|
444
|
|
|
|
445
|
|
|
|
442
|
|
|
|
458
|
|
|
|
482
|
|
Weighted average common shares outstanding diluted
|
|
|
444
|
|
|
|
450
|
|
|
|
448
|
|
|
|
470
|
|
|
|
499
|
|
Ratio of earnings to fixed charges(1)(2)
|
|
|
N/A
|
|
|
|
8.78
|
|
|
|
8.08
|
|
|
|
8.34
|
|
|
|
6.65
|
|
Ratio of earnings to combined fixed charges and preferred stock
dividends(1)(2)
|
|
|
N/A
|
|
|
|
8.54
|
|
|
|
7.85
|
|
|
|
8.13
|
|
|
|
6.48
|
|
Cash Flow Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
9,408
|
|
|
$
|
6,651
|
|
|
$
|
5,993
|
|
|
$
|
5,612
|
|
|
$
|
4,816
|
|
Net cash used in investing activities
|
|
$
|
(6,873
|
)
|
|
$
|
(5,714
|
)
|
|
$
|
(7,449
|
)
|
|
$
|
(1,652
|
)
|
|
$
|
(3,634
|
)
|
Net cash (used in) provided by financing activities
|
|
$
|
(3,408
|
)
|
|
$
|
(371
|
)
|
|
$
|
593
|
|
|
$
|
(3,543
|
)
|
|
$
|
(1,001
|
)
|
Production, Price and Other Data(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
53
|
|
|
|
55
|
|
|
|
42
|
|
|
|
46
|
|
|
|
54
|
|
Gas (Bcf)
|
|
|
940
|
|
|
|
863
|
|
|
|
808
|
|
|
|
819
|
|
|
|
883
|
|
NGLs (MMBbls)
|
|
|
28
|
|
|
|
26
|
|
|
|
23
|
|
|
|
24
|
|
|
|
24
|
|
Total (MMBoe)(4)
|
|
|
238
|
|
|
|
224
|
|
|
|
200
|
|
|
|
206
|
|
|
|
225
|
|
Realized prices without hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
86.22
|
|
|
$
|
63.98
|
|
|
$
|
57.39
|
|
|
$
|
48.01
|
|
|
$
|
36.42
|
|
Gas (per Mcf)
|
|
$
|
7.73
|
|
|
$
|
5.97
|
|
|
$
|
6.03
|
|
|
$
|
7.08
|
|
|
$
|
5.37
|
|
NGLs (per Bbl)
|
|
$
|
44.08
|
|
|
$
|
37.76
|
|
|
$
|
32.10
|
|
|
$
|
29.05
|
|
|
$
|
23.06
|
|
Combined (per Boe)(4)
|
|
$
|
54.97
|
|
|
$
|
42.90
|
|
|
$
|
40.19
|
|
|
$
|
42.18
|
|
|
$
|
32.26
|
|
Production and operating expenses per Boe(4)
|
|
$
|
11.52
|
|
|
$
|
9.68
|
|
|
$
|
8.81
|
|
|
$
|
7.65
|
|
|
$
|
6.38
|
|
Depreciation, depletion and amortization of oil and gas
properties per Boe(4)
|
|
$
|
13.68
|
|
|
$
|
11.85
|
|
|
$
|
10.27
|
|
|
$
|
8.56
|
|
|
$
|
8.15
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In millions)
|
|
|
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets(1)
|
|
$
|
31,908
|
|
|
$
|
41,456
|
|
|
$
|
35,063
|
|
|
$
|
30,273
|
|
|
$
|
30,025
|
|
Long-term debt
|
|
$
|
5,661
|
|
|
$
|
6,924
|
|
|
$
|
5,568
|
|
|
$
|
5,957
|
|
|
$
|
7,031
|
|
Stockholders equity
|
|
$
|
17,060
|
|
|
$
|
22,006
|
|
|
$
|
17,442
|
|
|
$
|
14,862
|
|
|
$
|
13,674
|
|
|
|
|
(1) |
|
During 2008, we recorded a $10.4 billion ($7.1 billion
after income taxes) noncash reduction of the carrying values of
certain oil and gas properties as discussed in Note 13 of
the consolidated financial statements. |
|
(2) |
|
For purposes of calculating the ratio of earnings to fixed
charges and the ratio of earnings to combined fixed charges and
preferred stock dividends, (i) earnings consist of earnings
from continuing operations before income taxes, plus fixed
charges; (ii) fixed charges consist of interest expense,
dividends on subsidiarys preferred stock and one-third of
rental expense estimated to be attributable to interest; and
(iii) preferred stock dividends consist of the amount of
pre-tax earnings required to pay dividends on the outstanding
preferred stock. |
|
|
|
For the year 2008, earnings were inadequate to cover fixed
charges and combined fixed charges and preferred stock dividends
by $4.1 billion primarily due to the noncash reduction of
the carrying values of certain oil and gas properties referred
to above. |
|
(3) |
|
The amounts presented under Production, Price and Other
Data exclude the amounts related to discontinued
operations in Egypt and West Africa. The price data presented
excludes the effects of unrealized and realized gains and losses
from our derivative financial instruments. |
|
|
|
Our production volumes in 2005 were affected by the sale of
certain non-core properties in the first half of the year, and
the suspension of a portion of our Gulf of Mexico production due
to hurricanes in the last half of the year. |
|
(4) |
|
Gas volumes are converted to Boe at the rate of six Mcf of gas
per barrel of oil, based upon the approximate relative energy
content of gas and oil, which rate is not necessarily indicative
of the relationship of gas and oil prices. NGL volumes are
converted to Boe on a one-to-one basis with oil. The respective
prices of oil, gas and NGLs are affected by market and other
factors in addition to relative energy content. |
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
Introduction
The following discussion and analysis presents managements
perspective of our business, financial condition and overall
performance. This information is intended to provide investors
with an understanding of our past performance, current financial
condition and outlook for the future and should be reviewed in
conjunction with our Selected Financial Data and
Financial Statements and Supplementary Data. Our
discussion and analysis relates to the following subjects:
|
|
|
|
|
Overview of Business
|
|
|
|
Overview of 2008 Results
|
|
|
|
Business and Industry Outlook
|
|
|
|
Results of Operations
|
|
|
|
Capital Resources, Uses and Liquidity
|
|
|
|
Contingencies and Legal Matters
|
|
|
|
Critical Accounting Policies and Estimates
|
|
|
|
Recently Issued Accounting Standards Not Yet Adopted
|
|
|
|
Modernization of Oil and Gas Reporting
|
31
|
|
|
|
|
Forward-Looking Estimates
|
Overview
of Business
Devon is one of the worlds leading independent oil and gas
exploration and production companies. Our operations are focused
primarily in the United States and Canada. However, we also
explore for and produce oil and gas in select international
areas, including Azerbaijan, Brazil and China. We also own
natural gas pipelines and treatment facilities in many of our
producing areas, making us one of North Americas larger
processors of natural gas liquids.
Our portfolio of oil and gas properties provides stable
production and a platform for future growth. Over
90 percent of our production from continuing operations is
from North America. Our production mix in 2008 was approximately
65% gas and 35% oil and NGLs such as propane, butane and ethane.
We are currently producing 2.6 Bcf of gas each day, or
about 3% of all the gas consumed in North America.
In managing our global operations, we have an operating strategy
that is focused on creating and increasing value per share. Key
elements of this strategy are building oil and gas reserves and
production, exercising capital discipline and controlling
operating costs. We also use our marketing and midstream
operations to improve our overall performance. Finally, we must
continually preserve our financial flexibility to achieve
sustainable, long-term success.
|
|
|
|
|
Reserves and production growth Our financial
condition and profitability are significantly affected by the
amount of proved reserves we own. Oil and gas properties are our
most significant assets, and the reserves that relate to such
properties are key to our future success. To increase our proved
reserves, we must replace quantities produced with additional
reserves from successful exploration and development activities
or property acquisitions. Additionally, our profitability and
operating cash flows are largely dependent on the amount of oil,
gas and NGLs we produce. Growing production from existing
properties is difficult because the rate of production from oil
and gas properties generally declines as reserves are depleted.
As a result, we constantly drill for and develop reserves on
properties that provide a balance of near-term and long-term
production. In addition, we may acquire properties with proved
reserves that we can develop and subsequently produce to help us
meet our production goals.
|
|
|
|
Capital investment discipline Effectively
deploying our resources into capital projects is key to
maintaining and growing future production and oil and gas
reserves. As a result, we have historically deployed virtually
all our available cash flow into capital projects. Therefore,
maintaining a disciplined approach to investing in capital
projects is important to our profitability and financial
condition. Our ability to control capital expenditures can be
affected by changes in commodity prices. During times of high
commodity prices, drilling and related costs often escalate due
to the effects of supply versus demand economics. The inverse is
also true.
|
Approximately two-thirds of our planned 2009 investment in
capital projects is dedicated to a foundation of low-risk
projects primarily in North America. The remainder of our
capital has been identified for longer-term projects primarily
in new unconventional natural gas plays in several United States
onshore regions, as well as continued offshore activities in the
Gulf of Mexico, Brazil and China. By deploying our capital in
this manner, we are able to consistently deliver cost-efficient
drill-bit growth and provide a strong source of cash flow while
balancing short-term and long-term growth targets.
|
|
|
|
|
Operating cost controls To maintain our
competitive position, we must control our lease operating costs
and other production costs. As reservoirs are depleted and
production rates decline, per unit production costs will
generally increase and affect our profitability and operating
cash flows. Similar to capital expenditures, our ability to
control operating costs can be affected by significant changes
in commodity prices. Our base North American production is
focused in core areas of our operations where we can achieve
economies of scale to help manage our operating costs.
|
|
|
|
Marketing & midstream performance improvement
We enhance the value of our oil and gas
operations with our marketing and midstream business. By
efficiently gathering and processing oil, gas
|
32
|
|
|
|
|
and NGL production, our midstream operations contribute to our
strategies to grow reserves and production and manage
expenditures. Additionally, by effectively marketing our
production, we maximize the prices received for our oil, gas and
NGL production in relation to market prices. This is important
because our profitability is highly dependent on market prices.
These prices are determined primarily by market conditions.
Market conditions for these products have been, and will
continue to be, influenced by regional and worldwide economic
activity, weather and other factors that are beyond our control.
To manage this volatility, we sometimes utilize financial
hedging arrangements and fixed-price physical delivery
contracts. As of February 16, 2009, approximately 10% of
our 2009 gas production is associated with financial price
collars or fixed-price contracts.
|
|
|
|
|
|
Financial flexibility preservation As
mentioned, commodity prices have been and will continue to be
volatile and will continue to impact our profitability and cash
flow. We understand this fact and manage our debt levels
accordingly to preserve our liquidity and financial flexibility.
We generally operate within the cash flow generated by our
operations. However, during periods of low commodity prices, we
may use our balance sheet strength to access debt or equity
markets, allowing us to preserve our business and maintain
momentum until markets recover. When prices improve, we can
utilize excess operating cash flow to repay debt and invest in
our activities that not only maintain but also increase value
per share.
|
Overview
of 2008 Results
2008 was a year of contrasts. By many measures, 2008 was
the best year in our history. Throughout the year, we achieved
key operational successes as we continued to execute on our
operating strategy. We drilled a record amount of wells with a
98% success rate and delivered a record amount of operating cash
flow. As a result of our operational success and rising
commodity prices, in the third quarter of 2008, we reported the
largest quarterly earnings in our history.
However, sharp declines in oil, gas and NGL prices during the
fourth quarter caused us to record noncash impairments of our
oil and gas properties totaling $7.1 billion, net of income
taxes. Due to this impairment charge, our record earnings in the
third quarter were immediately followed by a record quarterly
loss in the fourth quarter.
We account for our oil and gas properties using the full cost
accounting method. Full cost impairment calculations require the
use of quarter-end prices. As a result, such calculations do not
indicate the true fair value of the underlying reserves because
of the volatile nature of commodity prices. In fact, the SEC
recently recognized that impairment calculations based upon
prices as of a single day of the year are not ideal and issued
new rules that require the use of
12-month
average prices for impairment calculations. These new rules will
be effective for our 2009 year-end reporting. Had these new
rules been in place as of December 31, 2008, we would not
have recognized the noncash impairments.
Key measures of our performance for 2008, as well as certain
operational developments, are summarized below:
|
|
|
|
|
Production grew 6% over 2007, to 238 million Boe.
|
|
|
|
The combined realized price for oil, gas and NGLs per Boe
increased 28% to $54.97.
|
|
|
|
Marketing and midstream operating profit climbed to a record
$668 million.
|
|
|
|
Production and operating costs increased 19% per Boe due to our
large-scale projects at Jackfish in Canada and Polvo in Brazil,
which are experiencing higher
per-unit
costs while they are in the early phases of production.
|
|
|
|
Operating cash flow reached $9.4 billion, representing a
41% increase over 2008.
|
|
|
|
Capitalized costs incurred in our oil and gas exploration and
development activities were $9.8 billion in 2008.
|
33
Despite these positive results, we reported a net loss of
$2.1 billion, or $4.85 per diluted share, for 2008. This
represents a $5.8 billion decrease in earnings compared to
2007, which was primarily attributable to the $7.1 billion,
net of income tax, property impairments recognized in the fourth
quarter of 2008.
From an operational perspective, we completed another successful
year with the drill-bit. We drilled a record 2,441 gross
wells with an overall 98% rate of success. This success rate
enabled us to increase proved reserves by 584 million Boe,
which represented nearly 2 and one half times our 2008
production. Consistent with our two-pronged operating strategy,
93% of the wells we drilled were North American development
wells.
Besides completing another successful year of drilling, we also
had several other key operational achievements during 2008. In
the Gulf of Mexico, we continued to build off prior years
successful drilling results with our deepwater exploration and
development program. At Cascade, we commenced drilling the first
of two initial producing wells and continued work on production
facilities and subsea equipment. We also continued progressing
toward commercial development of our other previous discoveries
in the Lower Tertiary trend of the Gulf of Mexico. We also added
some 800,000 net undeveloped acres to our lease inventory,
positioning us with more than 1.4 million net acres in four
emerging unconventional natural gas plays in the United States.
In 2008, we substantially completed our African divestiture
program. We have now sold all our oil and gas producing
properties in Africa, generating aggregate proceeds of
$2.2 billion after income taxes.
Additionally, on October 31, 2008, we transferred our
14.2 million shares of Chevron common stock to Chevron. In
exchange, we received Chevrons interest in the
Drunkards Wash coalbed natural gas field in east-central
Utah and $280 million in cash. The field has approximately
51,000 net acres and had net production of about
40 million cubic feet of natural gas equivalent per day at
the time of the exchange.
Even with the fourth quarter net loss, we strengthened our
financial position during 2008. We used cash on hand, operating
cash flow, divestiture proceeds and Chevron exchange proceeds to
fund $9.4 billion of capital expenditures, reduce debt by
$2.1 billion, repurchase $815 million of common and
preferred stock and pay $289 million of dividends. At the
end of 2008, we had $379 million of cash, and as of
January 31, 2009, we had $3.1 billion of availability
under our credit lines.
Business
and Industry Outlook
As previously mentioned, our current and future earnings depend
largely on our ability to replace and grow oil and gas reserves,
increase production and exert cost discipline. We must also
manage commodity pricing risks to achieve long-term success.
Oil and gas prices reached historical high levels in recent
years and during the first half of 2008. We have utilized the
record operating cash flows generated by high commodity prices,
along with proceeds from our African divestitures, to, among
other uses, repay outstanding debt. During 2008 and 2007, we
repaid outstanding debt totaling $3.9 billion. During this
same period, we also repurchased $1.0 billion of our common
stock and redeemed $150 million of preferred stock. High
commodity prices have also been a key factor driving cost
increases in the oil and gas industry that have exceeded general
inflation trends. We are no different from others in the
industry in that we have been impacted by these cost increases.
As we exited the third quarter of 2008, oil and gas prices had
declined sharply from their recent record levels and declined
even further through the end of 2008. In addition, recent
problems in the credit markets, steep stock market declines,
financial institution failures and government bail-outs provide
evidence of a weakening United States and global economy. As a
result of the market turmoil and price decreases, oil and gas
companies with high debt levels and lack of liquidity have been,
and will continue to be, negatively impacted. However, we do not
consider ourselves to be in this category based on our current
debt level and credit availability.
The only constant in the oil and gas business is volatility, and
2008 presented us with some remarkable reminders. Our response
to the current environment is to dramatically cut capital
expenditures. We are
34
budgeting exploration and development capital at
$3.5 billion to $4.1 billion for 2009. This is less
than half of our 2008 investment in exploration and development.
With the addition of non-oil and gas capital and other
capitalized costs, we are forecasting total 2009 capital
expenditures of $4.7 billion to $5.4 billion.
Assuming average benchmark prices of $45.00 per barrel of crude
oil and $5.50 per Mcf of gas, our 2009 capital budget will
require deficit spending of about $1 billion. Our
philosophy has always been to live roughly within our cash flow,
and we clearly will not continue to spend at this rate in future
years without some improvement in oil and gas prices. However,
in order to preserve our business and maintain a level of
momentum that will allow us to take advantage of stronger prices
when markets recover, we believe it is prudent to use our
balance sheet strength to fund this additional $1 billion
of spending in 2009. If we see further price weakness in 2009 or
beyond, we are prepared to make further cuts.
We are dramatically decreasing our activity across most of our
near-term development projects in North America. We will
continue activity at a rate that will keep us competitive, but
at a far lower level than in 2008. However, we are going to
continue the momentum of some of our longer-term growth projects
that will position us to bring on new production when oil and
gas demand recovers. We are continuing to fund the second phase
of our operations at Jackfish and the evaluation and development
of our Lower Tertiary assets in the Gulf of Mexico. We will also
move forward with the evaluation of our sizable acreage
positions in several emerging natural gas plays in North America.
This decrease in development drilling will impact our oil and
gas production. We are currently forecasting our 2009 production
will be essentially flat with that of 2008.
We are fortunate that we are positioned to withstand the
downturn in the global economy and the resulting weakness in oil
and gas prices. The strength of our balance sheet and the
quality of our oil and gas properties position us to emerge from
the current environment and prosper in the future.
Results
of Operations
Revenues
Changes in oil, gas and NGL production, prices and revenues from
2006 to 2008 are shown in the following tables. The amounts for
all periods presented exclude results from our Egyptian and West
African operations which are presented as discontinued
operations. Unless otherwise stated, all dollar amounts are
expressed in U.S. dollars.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2008 vs
|
|
|
|
|
|
2007 vs
|
|
|
|
|
|
|
2008
|
|
|
2007(2)
|
|
|
2007
|
|
|
2006(2)
|
|
|
2006
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
53
|
|
|
|
−3
|
%
|
|
|
55
|
|
|
|
+29
|
%
|
|
|
42
|
|
Gas (Bcf)
|
|
|
940
|
|
|
|
+9
|
%
|
|
|
863
|
|
|
|
+7
|
%
|
|
|
808
|
|
NGLs (MMBbls)
|
|
|
28
|
|
|
|
+10
|
%
|
|
|
26
|
|
|
|
+10
|
%
|
|
|
23
|
|
Total (MMBoe)(1)
|
|
|
238
|
|
|
|
+6
|
%
|
|
|
224
|
|
|
|
+12
|
%
|
|
|
200
|
|
Realized prices without hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
86.22
|
|
|
|
+35
|
%
|
|
$
|
63.98
|
|
|
|
+11
|
%
|
|
$
|
57.39
|
|
Gas (per Mcf)
|
|
$
|
7.73
|
|
|
|
+29
|
%
|
|
$
|
5.97
|
|
|
|
−1
|
%
|
|
$
|
6.03
|
|
NGLs (per Bbl)
|
|
$
|
44.08
|
|
|
|
+17
|
%
|
|
$
|
37.76
|
|
|
|
+18
|
%
|
|
$
|
32.10
|
|
Combined (per Boe)(1)
|
|
$
|
54.97
|
|
|
|
+28
|
%
|
|
$
|
42.90
|
|
|
|
+7
|
%
|
|
$
|
40.19
|
|
Revenues ($ in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
4,567
|
|
|
|
+31
|
%
|
|
$
|
3,493
|
|
|
|
+44
|
%
|
|
$
|
2,434
|
|
Gas
|
|
|
7,263
|
|
|
|
+41
|
%
|
|
|
5,149
|
|
|
|
+6
|
%
|
|
|
4,874
|
|
NGLs
|
|
|
1,243
|
|
|
|
+28
|
%
|
|
|
970
|
|
|
|
+30
|
%
|
|
|
749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
13,073
|
|
|
|
+36
|
%
|
|
$
|
9,612
|
|
|
|
+19
|
%
|
|
$
|
8,057
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2008 vs
|
|
|
|
|
|
2007 vs
|
|
|
|
|
|
|
2008
|
|
|
2007(2)
|
|
|
2007
|
|
|
2006(2)
|
|
|
2006
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
17
|
|
|
|
−9
|
%
|
|
|
19
|
|
|
|
−3
|
%
|
|
|
19
|
|
Gas (Bcf)
|
|
|
726
|
|
|
|
+14
|
%
|
|
|
635
|
|
|
|
+12
|
%
|
|
|
566
|
|
NGLs (MMBbls)
|
|
|
24
|
|
|
|
+13
|
%
|
|
|
22
|
|
|
|
+15
|
%
|
|
|
19
|
|
Total (MMBoe)(1)
|
|
|
162
|
|
|
|
+11
|
%
|
|
|
146
|
|
|
|
+10
|
%
|
|
|
132
|
|
Realized prices without hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
98.83
|
|
|
|
+43
|
%
|
|
$
|
69.23
|
|
|
|
+11
|
%
|
|
$
|
62.23
|
|
Gas (per Mcf)
|
|
$
|
7.59
|
|
|
|
+29
|
%
|
|
$
|
5.87
|
|
|
|
−2
|
%
|
|
$
|
6.02
|
|
NGLs (per Bbl)
|
|
$
|
41.21
|
|
|
|
+14
|
%
|
|
$
|
36.11
|
|
|
|
+23
|
%
|
|
$
|
29.42
|
|
Combined (per Boe)(1)
|
|
$
|
50.55
|
|
|
|
+27
|
%
|
|
$
|
39.77
|
|
|
|
+2
|
%
|
|
$
|
39.03
|
|
Revenues ($ in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
1,698
|
|
|
|
+29
|
%
|
|
$
|
1,313
|
|
|
|
+8
|
%
|
|
$
|
1,218
|
|
Gas
|
|
|
5,511
|
|
|
|
+48
|
%
|
|
|
3,728
|
|
|
|
+9
|
%
|
|
|
3,407
|
|
NGLs
|
|
|
997
|
|
|
|
+29
|
%
|
|
|
773
|
|
|
|
+41
|
%
|
|
|
548
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
8,206
|
|
|
|
+41
|
%
|
|
$
|
5,814
|
|
|
|
+12
|
%
|
|
$
|
5,173
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2008 vs
|
|
|
|
|
|
2007 vs
|
|
|
|
|
|
|
2008
|
|
|
2007(2)
|
|
|
2007
|
|
|
2006(2)
|
|
|
2006
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
22
|
|
|
|
+34
|
%
|
|
|
16
|
|
|
|
+26
|
%
|
|
|
13
|
|
Gas (Bcf)
|
|
|
212
|
|
|
|
−6
|
%
|
|
|
227
|
|
|
|
−6
|
%
|
|
|
241
|
|
NGLs (MMBbls)
|
|
|
4
|
|
|
|
−6
|
%
|
|
|
4
|
|
|
|
−9
|
%
|
|
|
4
|
|
Total (MMBoe)(1)
|
|
|
61
|
|
|
|
+5
|
%
|
|
|
58
|
|
|
|
+1
|
%
|
|
|
58
|
|
Realized prices without hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
71.04
|
|
|
|
+43
|
%
|
|
$
|
49.80
|
|
|
|
+6
|
%
|
|
$
|
46.94
|
|
Gas (per Mcf)
|
|
$
|
8.17
|
|
|
|
+31
|
%
|
|
$
|
6.24
|
|
|
|
+3
|
%
|
|
$
|
6.05
|
|
NGLs (per Bbl)
|
|
$
|
61.45
|
|
|
|
+33
|
%
|
|
$
|
46.07
|
|
|
|
+8
|
%
|
|
$
|
42.67
|
|
Combined (per Boe)(1)
|
|
$
|
57.65
|
|
|
|
+39
|
%
|
|
$
|
41.51
|
|
|
|
+6
|
%
|
|
$
|
39.21
|
|
Revenues ($ in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
1,535
|
|
|
|
+91
|
%
|
|
$
|
804
|
|
|
|
+33
|
%
|
|
$
|
603
|
|
Gas
|
|
|
1,733
|
|
|
|
+23
|
%
|
|
|
1,410
|
|
|
|
−3
|
%
|
|
|
1,456
|
|
NGLs
|
|
|
246
|
|
|
|
+25
|
%
|
|
|
197
|
|
|
|
−2
|
%
|
|
|
201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,514
|
|
|
|
+46
|
%
|
|
$
|
2,411
|
|
|
|
+7
|
%
|
|
$
|
2,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2008 vs
|
|
|
|
|
|
2007 vs
|
|
|
|
|
|
|
2008
|
|
|
2007(2)
|
|
|
2007
|
|
|
2006(2)
|
|
|
2006
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
14
|
|
|
|
−27
|
%
|
|
|
20
|
|
|
|
+95
|
%
|
|
|
10
|
|
Gas (Bcf)
|
|
|
2
|
|
|
|
+29
|
%
|
|
|
1
|
|
|
|
−6
|
%
|
|
|
1
|
|
NGLs (MMBbls)
|
|
|
|
|
|
|
N/M
|
|
|
|
|
|
|
|
N/M
|
|
|
|
|
|
Total (MMBoe)(1)
|
|
|
15
|
|
|
|
−26
|
%
|
|
|
20
|
|
|
|
+92
|
%
|
|
|
10
|
|
Realized prices without hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
94.05
|
|
|
|
+33
|
%
|
|
$
|
70.60
|
|
|
|
+15
|
%
|
|
$
|
61.35
|
|
Gas (per Mcf)
|
|
$
|
8.27
|
|
|
|
+33
|
%
|
|
$
|
6.22
|
|
|
|
+3
|
%
|
|
$
|
6.05
|
|
NGLs (per Bbl)
|
|
$
|
|
|
|
|
N/M
|
|
|
$
|
|
|
|
|
N/M
|
|
|
$
|
|
|
Combined (per Boe)(1)
|
|
$
|
92.91
|
|
|
|
+33
|
%
|
|
$
|
70.11
|
|
|
|
+16
|
%
|
|
$
|
60.60
|
|
Revenues ($ in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
1,334
|
|
|
|
−3
|
%
|
|
$
|
1,376
|
|
|
|
+125
|
%
|
|
$
|
613
|
|
Gas
|
|
|
19
|
|
|
|
+72
|
%
|
|
|
11
|
|
|
|
−3
|
%
|
|
|
11
|
|
NGLs
|
|
|
|
|
|
|
N/M
|
|
|
|
|
|
|
|
N/M
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,353
|
|
|
|
−2
|
%
|
|
$
|
1,387
|
|
|
|
+122
|
%
|
|
$
|
624
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gas volumes are converted to Boe or MMBoe at the rate of six Mcf
of gas per barrel of oil, based upon the approximate relative
energy content of gas and oil, which rate is not necessarily
indicative of the relationship of gas and oil prices. NGL
volumes are converted to Boe on a one-to-one basis with oil. |
|
(2) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in this
table. |
N/M Not meaningful.
The volume and price changes in the tables above caused the
following changes to our oil, gas and NGL sales between 2006 and
2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGL
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2006 sales
|
|
$
|
2,434
|
|
|
$
|
4,874
|
|
|
$
|
749
|
|
|
$
|
8,057
|
|
Changes due to volumes
|
|
|
700
|
|
|
|
327
|
|
|
|
76
|
|
|
|
1,103
|
|
Changes due to prices
|
|
|
359
|
|
|
|
(52
|
)
|
|
|
145
|
|
|
|
452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 sales
|
|
|
3,493
|
|
|
|
5,149
|
|
|
|
970
|
|
|
|
9,612
|
|
Changes due to volumes
|
|
|
(104
|
)
|
|
|
462
|
|
|
|
95
|
|
|
|
453
|
|
Changes due to prices
|
|
|
1,178
|
|
|
|
1,652
|
|
|
|
178
|
|
|
|
3,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 sales
|
|
$
|
4,567
|
|
|
$
|
7,263
|
|
|
$
|
1,243
|
|
|
$
|
13,073
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
Sales
2008 vs. 2007 Oil sales increased $1.2 billion as a
result of a 35% increase in our realized price without hedges.
The average NYMEX West Texas Intermediate index price increased
38% during the same time period, accounting for the majority of
the increase.
Oil sales decreased $104 million due to a two million
barrel decrease in production. Our International production
decreased approximately six million barrels due to reaching
certain cost recovery thresholds of our carried interest in
Azerbaijan. We also deferred 0.5 million barrels of oil
production due to hurricanes. These
37
decreases were partially offset by additional production
resulting from increased development activity at our Jackfish
and Lloydminster areas in Canada and at our Polvo development in
Brazil.
2007 vs. 2006 Oil sales increased $700 million due
to a 13 million barrel increase in production. The increase
in our 2007 oil production was primarily due to our properties
in Azerbaijan where we achieved payout of certain carried
interests in the last half of 2006. This led to a nine million
barrel increase in 2007 as compared to 2006. Production also
increased 3.5 million barrels due to increased development
activity in our Lloydminster area in Canada. Also, oil sales
from our Polvo field in Brazil began during the fourth quarter
of 2007, which resulted in 0.5 million barrels of increased
production.
Oil sales increased $359 million as a result of an 11%
increase in our realized price without hedges. The average NYMEX
West Texas Intermediate index price increased 9% during the same
time period, accounting for the majority of the increase.
Gas
Sales
2008 vs. 2007 Gas sales increased $1.7 billion as a
result of a 29% increase in our realized price without hedges.
This increase was largely due to increases in the regional index
prices upon which our gas sales are based.
A 77 Bcf increase in production during 2008 caused gas
sales to increase by $462 million. Our drilling and
development program in the Barnett Shale field in north Texas
contributed 83 Bcf to the gas production increase. This
increase and the effect of new drilling and development in our
other North American properties were partially offset by natural
production declines and the deferral of seven Bcf of production
in 2008 due to hurricanes.
2007 vs. 2006 A 55 Bcf increase in production caused
gas sales to increase by $327 million. Our drilling and
development program in the Barnett Shale field in north Texas
contributed 53 Bcf to the gas production increase. The June
2006 Chief Holdings LLC (Chief) acquisition also
contributed 12 Bcf of increased production. During 2007, we
also began first production from the Merganser field in the
deepwater Gulf of Mexico, which resulted in seven Bcf of
increased production. These increases and the effects of new
drilling and development in our other North American properties
were partially offset by natural production declines primarily
in Canada.
A 1% decline in our average realized price without hedges caused
gas sales to decrease $52 million in 2007.
38
Net
(Loss) Gain on Oil and Gas Derivative Financial
Instruments
The following tables provide financial information associated
with our oil and gas hedges from 2006 to 2008. The first table
presents the cash settlements and unrealized gains and losses
recognized as components of our revenues. The subsequent tables
present our oil, gas and NGL prices with, and without, the
effects of the cash settlements from 2006 to 2008. The prices do
not include the effects of unrealized gains and losses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Cash settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps
|
|
$
|
(203
|
)
|
|
$
|
38
|
|
|
$
|
|
|
Gas price collars
|
|
|
(221
|
)
|
|
|
2
|
|
|
|
|
|
Oil price collars
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements (paid) received
|
|
|
(397
|
)
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) on fair value changes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps
|
|
|
(12
|
)
|
|
|
(22
|
)
|
|
|
34
|
|
Gas price collars
|
|
|
255
|
|
|
|
(4
|
)
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses) on fair value changes
|
|
|
243
|
|
|
|
(26
|
)
|
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) gain on oil and gas derivative financial instruments
|
|
$
|
(154
|
)
|
|
$
|
14
|
|
|
$
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
Total
|
|
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Boe)
|
|
|
Realized price without hedges
|
|
$
|
86.22
|
|
|
$
|
7.73
|
|
|
$
|
44.08
|
|
|
$
|
54.97
|
|
Cash settlements of hedges
|
|
|
0.51
|
|
|
|
(0.45
|
)
|
|
|
|
|
|
|
(1.67
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements
|
|
$
|
86.73
|
|
|
$
|
7.28
|
|
|
$
|
44.08
|
|
|
$
|
53.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
Total
|
|
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Boe)
|
|
|
Realized price without hedges
|
|
$
|
63.98
|
|
|
$
|
5.97
|
|
|
$
|
37.76
|
|
|
$
|
42.90
|
|
Cash settlements
|
|
|
|
|
|
|
0.04
|
|
|
|
|
|
|
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized cash price
|
|
$
|
63.98
|
|
|
$
|
6.01
|
|
|
$
|
37.76
|
|
|
$
|
43.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
Total
|
|
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Boe)
|
|
|
Realized price without hedges
|
|
$
|
57.39
|
|
|
$
|
6.03
|
|
|
$
|
32.10
|
|
|
$
|
40.19
|
|
Cash settlements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized cash price
|
|
$
|
57.39
|
|
|
$
|
6.03
|
|
|
$
|
32.10
|
|
|
$
|
40.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our oil and gas derivative financial instruments include price
swaps and costless price collars. For the price swaps, we
receive a fixed price for our production and pay a variable
market price to the contract counterparty. The costless price
collars set a floor and ceiling price for the hedged production.
If the applicable monthly price indices are outside of the
ranges set by the floor and ceiling prices in the various
collars, we cash-settle the difference with the counterparty.
Cash settlements as presented in the tables above represent
realized losses or gains related to our price swaps and collars.
39
During 2008, we received $27 million, or $0.51 per Bbl,
from counterparties to settle our oil price collars. We paid
$424 million, or $0.45 per Mcf, to counterparties during
2008 to settle our gas price swaps and collars. During 2007, we
received $40 million, or $0.04 per Mcf, from counterparties
to settle our gas price swaps and collars. In 2006, cash
payments related to our gas price swaps and collars were
completely offset by cash receipts.
In addition to recognizing these cash settlement effects, we
also recognize unrealized changes in the fair values of our oil
and gas derivative instruments in each reporting period. We
estimate the fair values of our oil and gas derivative financial
instruments primarily by using internal discounted cash flow
calculations. From time to time, we validate our valuation
techniques by comparing our internally generated fair value
estimates with those obtained from contract counterparties or
brokers.
The most significant variable to our cash flow calculations is
our estimate of future commodity prices. We base our estimate of
future prices upon published forward commodity price curves such
as the Inside FERC Henry Hub forward curve for gas instruments
and the NYMEX West Texas Intermediate forward curve for oil
instruments. Based on the amount of volumes subject to price
swaps and collars at December 31, 2008, a 10% increase in
these forward curves would have decreased our 2008 unrealized
gain for our oil and gas collar derivative financial instruments
by approximately $54 million. Another key input to our cash
flow calculations is our estimate of volatility for these
forward curves, which we base primarily upon implied volatility.
Counterparty credit risk is also a component of commodity
derivative valuations. We have mitigated our exposure to any
single counterparty by contracting with numerous counterparties.
Our commodity derivative contracts are held with eight separate
counterparties. Additionally, our derivative contracts generally
require cash collateral to be posted if either our or the
counterpartys credit rating falls below investment
grade. The threshold for collateral posting decreases as
the debt rating falls further below investment grade. Such
thresholds generally range from zero to $50 million for the
majority of our contracts. As of December 31, 2008, the
credit ratings of all our counterparties were investment grade.
The $243 million net unrealized gain recognized in 2008 was
primarily the result of a decrease in the Inside FERC Henry Hub
forward curve subsequent to our contract trade dates.
Marketing
and Midstream Revenues and Operating Costs and
Expenses
The details of the changes in marketing and midstream revenues,
operating costs and expenses and the resulting operating profit
between 2006 and 2008 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2008 vs
|
|
|
|
|
|
2007 vs
|
|
|
|
|
|
|
2008
|
|
|
2007(1)
|
|
|
2007
|
|
|
2006(1)
|
|
|
2006
|
|
|
|
|
|
|
($ in millions)
|
|
|
|
|
|
Marketing and midstream:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
2,292
|
|
|
|
+32
|
%
|
|
$
|
1,736
|
|
|
|
+4
|
%
|
|
$
|
1,672
|
|
Operating costs and expenses
|
|
|
1,624
|
|
|
|
+32
|
%
|
|
|
1,227
|
|
|
|
−1
|
%
|
|
|
1,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit
|
|
$
|
668
|
|
|
|
+31
|
%
|
|
$
|
509
|
|
|
|
+17
|
%
|
|
$
|
436
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in this
table. |
2008 vs. 2007 Marketing and midstream revenues increased
$556 million and operating costs and expenses increased
$397 million, causing operating profit to increase
$159 million. Both revenues and expenses increased
primarily due to higher natural gas and NGL prices and increased
gas pipeline throughput.
2007 vs. 2006 Marketing and midstream revenues increased
$64 million, while operating costs and expenses decreased
$9 million, causing operating profit to increase
$73 million. Revenues increased primarily due to higher
prices realized on NGL sales.
40
Oil,
Gas and NGL Production and Operating Expenses
The details of the changes in oil, gas and NGL production and
operating expenses between 2006 and 2008 are shown in the table
below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2008 vs
|
|
|
|
|
|
2007 vs
|
|
|
|
|
|
|
2008
|
|
|
2007(1)
|
|
|
2007
|
|
|
2006(1)
|
|
|
2006
|
|
|
Production and operating expenses ($ in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
2,217
|
|
|
|
+21
|
%
|
|
$
|
1,828
|
|
|
|
+28
|
%
|
|
$
|
1,425
|
|
Production taxes
|
|
|
522
|
|
|
|
+53
|
%
|
|
|
340
|
|
|
|
|
|
|
|
341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production and operating expenses
|
|
$
|
2,739
|
|
|
|
+26
|
%
|
|
$
|
2,168
|
|
|
|
+23
|
%
|
|
$
|
1,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
9.32
|
|
|
|
+14
|
%
|
|
$
|
8.16
|
|
|
|
+15
|
%
|
|
$
|
7.11
|
|
Production taxes
|
|
|
2.20
|
|
|
|
+44
|
%
|
|
|
1.52
|
|
|
|
−11
|
%
|
|
|
1.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production and operating expenses per Boe
|
|
$
|
11.52
|
|
|
|
+19
|
%
|
|
$
|
9.68
|
|
|
|
+10
|
%
|
|
$
|
8.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in this
table. |
Lease
Operating Expenses (LOE)
2008 vs. 2007 LOE increased $389 million in 2008.
The largest contributor to this increase, as well as the
increase in LOE per Boe, was higher
per-unit
costs associated with new thermal heavy oil production from our
Jackfish operations in Canada as well as new oil production from
Brazil. As these large-scale projects are in the early phases of
production,
per-unit
operating costs are higher than the
per-unit
costs for our overall portfolio of producing properties. LOE
also increased $112 million due to our 6% growth in
production. Additionally, LOE increased $31 million due to
damages to certain of our facilities and transportation systems
caused by Hurricane Ike in the third quarter of 2008. These
hurricane damages also contributed to the increase in LOE per
Boe.
2007 vs. 2006 LOE increased $403 million in 2007.
The largest contributor to this increase was our 12% growth in
production, which caused an increase of $168 million.
Another key contributor to the LOE increase was the effects of
inflationary pressure driven by increased competition for field
services. Increased demand for these services continued to drive
costs higher for materials, equipment and personnel used in both
recurring activities as well as well-workover projects during
2007. Furthermore, changes in the exchange rate between the
U.S. and Canadian dollar also caused LOE to increase
$40 million.
Production
Taxes
The following table details the changes in production taxes
between 2006 and 2008. The majority of our production taxes are
assessed on our onshore domestic properties. In the U.S., most
of the production taxes are based on a fixed percentage of
revenues. Therefore, the changes due to revenues in the table
primarily relate to changes in oil, gas and NGL revenues from
our U.S. onshore properties.
|
|
|
|
|
|
|
(In millions)
|
|
|
2006 production taxes
|
|
$
|
341
|
|
Change due to revenues
|
|
|
65
|
|
Change due to rate
|
|
|
(66
|
)
|
|
|
|
|
|
2007 production taxes
|
|
|
340
|
|
Change due to revenues
|
|
|
123
|
|
Change due to rate
|
|
|
59
|
|
|
|
|
|
|
2008 production taxes
|
|
$
|
522
|
|
|
|
|
|
|
2008 vs. 2007 Production taxes increased $59 million
due to an increase in the effective production tax rate in 2008.
Our higher production tax rates in 2008 were largely due to
higher rates in China, which are
41
based on the level of crude oil prices. As our realized price
for crude oil sales in China increases or decreases, production
tax rates will increase or decrease in a like manner.
2007 vs. 2006 Production taxes decreased $66 million
due to a decrease in the effective production tax rate in 2007.
Our lower production tax rates in 2007 were primarily due to an
increase in tax credits received on certain horizontal wells in
the state of Texas and the increase in Azerbaijan revenues
subsequent to the payouts of our carried interests in the last
half of 2006. Our Azerbaijan revenues are not subject to
production taxes. Therefore, the increased revenues generated in
Azerbaijan in 2007 caused our overall rate of production taxes
to decrease.
Depreciation,
Depletion and Amortization of Oil and Gas Properties
(DD&A)
DD&A of oil and gas properties is calculated by multiplying
the percentage of total proved reserve volumes produced during
the year, by the depletable base. The depletable
base represents our net capitalized investment plus future
development costs related to proved undeveloped reserves.
Generally, if reserve volumes are revised up or down, then the
DD&A rate per unit of production will change inversely.
However, if the depletable base changes, then the DD&A rate
moves in the same direction. The per unit DD&A rate is not
affected by production volumes. Absolute or total DD&A, as
opposed to the rate per unit of production, generally moves in
the same direction as production volumes. Oil and gas property
DD&A is calculated separately on a
country-by-country
basis.
The changes in our production volumes, DD&A rate per unit
and DD&A of oil and gas properties between 2006 and 2008
are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2008 vs
|
|
|
|
|
|
2007 vs
|
|
|
|
|
|
|
2008
|
|
|
2007(1)
|
|
|
2007
|
|
|
2006(1)
|
|
|
2006
|
|
|
Total production volumes (MMBoe)
|
|
|
238
|
|
|
|
+6
|
%
|
|
|
224
|
|
|
|
+12
|
%
|
|
|
200
|
|
DD&A rate ($ per Boe)
|
|
$
|
13.68
|
|
|
|
+15
|
%
|
|
$
|
11.85
|
|
|
|
+15
|
%
|
|
$
|
10.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A expense ($ in millions)
|
|
$
|
3,253
|
|
|
|
+23
|
%
|
|
$
|
2,655
|
|
|
|
+29
|
%
|
|
$
|
2,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in this
table. |
The following table details the increases in DD&A of oil
and gas properties between 2006 and 2008 due to the changes in
production volumes and DD&A rate presented in the table
above.
|
|
|
|
|
|
|
(In millions)
|
|
|
2006 DD&A
|
|
$
|
2,058
|
|
Change due to volumes
|
|
|
242
|
|
Change due to rate
|
|
|
355
|
|
|
|
|
|
|
2007 DD&A
|
|
|
2,655
|
|
Change due to volumes
|
|
|
164
|
|
Change due to rate
|
|
|
434
|
|
|
|
|
|
|
2008 DD&A
|
|
$
|
3,253
|
|
|
|
|
|
|
2008 vs. 2007 Oil and gas property related DD&A
increased $434 million due to a 15% increase in the
DD&A rate. The largest contributor to the rate increase was
inflationary pressure on both the costs incurred during 2008 as
well as the estimated development costs to be spent in future
periods on proved undeveloped reserves. Other factors
contributing to the rate increase include reductions in reserve
estimates due to lower 2008 year-end commodity prices and
the transfer of previously unproved costs to the depletable base
as a result of 2008 drilling activities. In addition to the
impact from the higher 2008 rate, our 6% production increase
caused oil and gas property related DD&A expense to
increase $164 million.
42
2007 vs. 2006 Oil and gas property related DD&A
increased $355 million due to a 15% increase in the
DD&A rate. The largest contributor to the rate increase was
inflationary pressure on both the costs incurred during 2007 as
well as the estimated development costs to be spent in future
periods on proved undeveloped reserves. Other factors
contributing to the rate increase include the transfer of
previously unproved costs to the depletable base as a result of
2007 drilling activities and a higher
Canadian-to-U.S. dollar exchange rate in 2007. The net
effect of these increases was partially offset by higher reserve
estimates due to higher 2007 year-end commodity prices. In
addition to the impact from the higher 2007 rate, our 12%
production increase caused oil and gas property related
DD&A expense to increase $242 million.
General
and Administrative Expenses (G&A)
Our net G&A consists of three primary components. The
largest of these components is the gross amount of expenses
incurred for personnel costs, office expenses, professional fees
and other G&A items. The gross amount of these expenses is
partially offset by two components. One is the amount of
G&A capitalized pursuant to the full cost method of
accounting related to exploration and development activities.
The other is the amount of G&A reimbursed by working
interest owners of properties for which we serve as the
operator. These reimbursements are received during both the
drilling and operational stages of a propertys life. The
gross amount of G&A incurred, less the amounts capitalized
and reimbursed, is recorded as net G&A in the
consolidated statements of operations. Net G&A includes
expenses related to oil, gas and NGL exploration and production
activities, as well as marketing and midstream activities. See
the following table for a summary of G&A expenses by
component.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
2008
|
|
|
vs 2007(1)
|
|
|
2007
|
|
|
vs 2006(1)
|
|
|
2006
|
|
|
|
|
|
|
($ in millions)
|
|
|
|
|
|
Gross G&A
|
|
$
|
1,188
|
|
|
|
+25
|
%
|
|
$
|
947
|
|
|
|
+26
|
%
|
|
$
|
749
|
|
Capitalized G&A
|
|
|
(406
|
)
|
|
|
+30
|
%
|
|
|
(312
|
)
|
|
|
+28
|
%
|
|
|
(243
|
)
|
Reimbursed G&A
|
|
|
(129
|
)
|
|
|
+6
|
%
|
|
|
(122
|
)
|
|
|
+12
|
%
|
|
|
(109
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A
|
|
$
|
653
|
|
|
|
+27
|
%
|
|
$
|
513
|
|
|
|
+29
|
%
|
|
$
|
397
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in this
table. |
2008 vs. 2007 Gross G&A increased $241 million.
The largest contributors to the increase were higher employee
compensation and benefits costs. These cost increases, which
were largely related to our growth and industry inflation during
most of 2008, caused gross G&A to increase
$184 million. Of this increase, $79 million related to
higher stock compensation.
Stock compensation increased $27 million in the second
quarter of 2008 due to a modification of the share-based
compensation arrangements for certain of our executives. The
modified compensation arrangements provide that executives who
meet certain years-of-service and age criteria can retire and
continue vesting in outstanding share-based grants. As a
condition to receiving the benefits of these modifications, the
executives must agree not to use or disclose Devons
confidential information and not to solicit Devons
employees and customers. The executives are required to agree to
these conditions at retirement and again in each subsequent year
until all grants have vested.
Although this modification does not accelerate the vesting of
the executives grants, it does accelerate the expense
recognition as executives approach the years-of-service and age
criteria. When the modification was made in the second quarter
of 2008, certain executives had already met the years-of-service
and age criteria. As a result, we recognized $27 million of
share-based compensation expense in the second quarter of 2008
related to this modification. In the fourth quarter of 2008, we
recognized an additional $16 million of stock compensation
for grants made to these executives. The additional expenses
would have been recognized in future reporting periods if the
modification had not been made and the executives continued
their employment at Devon.
43
The higher employee compensation and benefits costs, exclusive
of the accelerated stock compensation expense, were also the
primary factors that caused the $94 million increase in
capitalized G&A in 2008.
2007 vs. 2006 Gross G&A increased $198 million.
The largest contributors to this increase were higher employee
compensation and benefits costs. These cost increases, which
were related to our growth and industry inflation during 2007,
caused gross G&A to increase $134 million. Of
this increase, $55 million related to higher stock
compensation. In addition, changes in the
Canadian-to-U.S. dollar exchange rate caused a
$13 million increase in costs.
The factors discussed above were also the primary factors that
caused the $69 million increase in capitalized G&A in
2007.
Interest
Expense
The following schedule includes the components of interest
expense between 2006 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Interest based on debt outstanding
|
|
$
|
426
|
|
|
$
|
508
|
|
|
$
|
486
|
|
Capitalized interest
|
|
|
(111
|
)
|
|
|
(102
|
)
|
|
|
(79
|
)
|
Other interest
|
|
|
14
|
|
|
|
24
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense
|
|
$
|
329
|
|
|
$
|
430
|
|
|
$
|
421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding decreased $82 million
from 2007 to 2008. This decrease was largely due to lower
average outstanding amounts for commercial paper and credit
facility borrowings in 2008 than in 2007. The decrease in
borrowings resulted largely from the use of proceeds from our
West African divestiture program and cash flow from operations
to repay all commercial paper and credit facility borrowings in
the second quarter of 2008. Additionally, we retired debentures
with a face value of $652 million during 2008, primarily
during the third quarter.
Interest based on debt outstanding increased $22 million
from 2006 to 2007. This increase was largely due to higher
average outstanding amounts for commercial paper and credit
facility borrowings in 2007 than in 2006, partially offset by
the effects of repaying various maturing notes in 2007 and 2006.
Capitalized interest increased from 2007 to 2008 primarily due
to higher cumulative costs related to large-scale development
projects in the Gulf of Mexico and Brazil, partially offset by
lower capitalized interest resulting from the completion of the
Access Pipeline in Canada.
Capitalized interest increased from 2006 to 2007 primarily due
to higher cumulative costs related to large-scale development
projects in the Gulf of Mexico and Brazil. Higher cumulative
costs related to the development of the second phase of our
Jackfish heavy oil development project in Canada and the
construction of the related Access Pipeline also contributed to
the increase.
44
Change
in Fair Value of Other Financial Instruments
The details of the changes in fair value of other financial
instruments between 2006 and 2008 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Losses (gains) from:
|
|
|
|
|
|
|
|
|
|
|
|
|
Chevron common stock
|
|
$
|
363
|
|
|
$
|
(281
|
)
|
|
$
|
|
|
Option embedded in exchangeable debentures
|
|
|
(109
|
)
|
|
|
248
|
|
|
|
181
|
|
Interest rate swaps fair value changes
|
|
|
(104
|
)
|
|
|
(1
|
)
|
|
|
(3
|
)
|
Interest rate swaps settlements
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
149
|
|
|
$
|
(34
|
)
|
|
$
|
178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chevron
Common Stock and Related Embedded Option
Prior to 2007, we recognized unrealized changes in the fair
values of our investment in 14.2 million shares of Chevron
common stock as part of other comprehensive income. Effective
January 1, 2007 as a result of our adoption of Financial
Accounting Standard No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities Including
an Amendment of FASB Statement No. 115, we began
recognizing unrealized gains and losses on our investment in
Chevron common stock in net earnings rather than as part of
other comprehensive income. On October 31, 2008, we
exchanged these shares of Chevron common stock for
Chevrons interest in the Drunkards Wash properties
located in east-central Utah and $280 million in cash. In
accordance with the terms of the exchange, the fair value of our
investment in the Chevron shares was estimated to be $67.71 per
share on the exchange date. Prior to the exchange of these
shares, we calculated the fair value of our investment in
Chevron common stock using Chevrons published market price.
We also recognized unrealized changes in the fair value of the
conversion option embedded in the debentures exchangeable into
shares of Chevron common stock. The embedded option was not
actively traded in an established market. Therefore, we
estimated its fair value using quotes obtained from a broker for
trades occurring near the valuation date. Since the exchangeable
debentures were retired in August 2008, we will not recognize
any future gains or losses from the embedded option.
The loss during 2008 on our investment in Chevron common stock
was directly attributable to a $25.62 per share decrease in the
estimated fair value while we owned Chevrons common stock
during the year. The gain on the embedded option during 2008 was
directly attributable to the change in fair value of the Chevron
common stock from January 1, 2008 to the maturity date of
August 15, 2008. The gain on our investment in Chevron
common stock and loss on the embedded option during 2007 were
directly attributable to a $19.80 increase in the price per
share of Chevrons common stock during 2007.
Interest
Rate Swaps
We also recognize unrealized changes in the fair values of our
interest rate swaps each reporting period. We estimate the fair
values of our interest rate swap financial instruments primarily
by using internal discounted cash flow calculations based upon
forward interest-rate yields. From time to time, we validate our
valuation techniques by comparing our internally generated fair
value estimates with those obtained from contract counterparties
or brokers.
The most significant variable to our cash flow calculations is
our estimate of future interest rate yields. We base our
estimate of future yields upon our own internal model that
utilizes forward curves such as the LIBOR or the Federal Funds
Rate provided by a third party. Based on the notional amount
subject to the interest rate swaps at December 31, 2008, a
10% increase in these forward curves would have decreased our
2008 unrealized gain for our interest rate swaps by
approximately $3 million.
45
During 2008, we recorded a $104 million unrealized gain as
a result of changes in interest rates subsequent to the trade
dates of our contracts.
As previously discussed for our commodity derivative contracts,
counterparty credit risk is also a component of interest rate
derivative valuations. We have mitigated our exposure to any
single counterparty by contracting with numerous counterparties.
Our interest rate derivative contracts are held with five
separate counterparties and have cash collateral posting
requirements. Additionally, the credit ratings of all our
counterparties were investment grade as of December 31,
2008.
Reduction
of Carrying Value of Oil and Gas Properties
During 2008 and 2006, we reduced the carrying values of certain
of our oil and gas properties due to full cost ceiling
limitations and unsuccessful exploratory activities. A summary
of these reductions and additional discussion is provided below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2006
|
|
|
|
|
|
|
Net of
|
|
|
|
|
|
Net of
|
|
|
|
Gross
|
|
|
Taxes
|
|
|
Gross
|
|
|
Taxes
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Full cost ceiling limitations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
6,538
|
|
|
$
|
4,168
|
|
|
$
|
|
|
|
$
|
|
|
Canada
|
|
|
3,353
|
|
|
|
2,488
|
|
|
|
|
|
|
|
|
|
Brazil
|
|
|
437
|
|
|
|
437
|
|
|
|
|
|
|
|
|
|
Russia
|
|
|
36
|
|
|
|
17
|
|
|
|
20
|
|
|
|
10
|
|
Indonesia
|
|
|
15
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
Unsuccessful exploratory activities Brazil
|
|
|
|
|
|
|
|
|
|
|
16
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,379
|
|
|
$
|
7,115
|
|
|
$
|
36
|
|
|
$
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
Reductions
The 2008 reductions were all recognized in the fourth quarter of
2008 and resulted primarily from a significant decrease in each
countrys full cost ceiling. The lower ceiling values
largely resulted from the effects of sharp declines in oil, gas
and NGL prices compared to previous quarter-end prices. To
demonstrate this decline, the December 31, 2008 and
September 30, 2008 weighted average wellhead prices for the
United States, Canada and Brazil are presented in the following
table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
September 30, 2008
|
|
Country
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
United States
|
|
$
|
42.21
|
|
|
$
|
4.68
|
|
|
$
|
16.16
|
|
|
$
|
97.62
|
|
|
$
|
5.28
|
|
|
$
|
38.00
|
|
Canada
|
|
$
|
23.23
|
|
|
$
|
5.31
|
|
|
$
|
20.89
|
|
|
$
|
59.72
|
|
|
$
|
6.00
|
|
|
$
|
62.78
|
|
Brazil
|
|
$
|
26.61
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
$
|
81.56
|
|
|
|
N/A
|
|
|
|
N/A
|
|
N/A Not applicable.
The December 31, 2008 oil and gas wellhead prices in the
table above compare to the NYMEX cash price of $44.60 per Bbl
for crude oil and the Henry Hub spot price of $5.71 per MMBtu
for gas. The September 30, 2008, wellhead prices in the
table compare to the NYMEX cash price of $100.64 per Bbl for
crude oil and the Henry Hub spot price of $7.12 per MMBtu for
gas.
2006
Reductions
As a result of a decline in the estimated future net revenues,
the carrying value of our Russian oil and gas properties
exceeded the full cost ceiling by $10 million at the end of
the third quarter of 2006. Therefore, we
46
recognized a $20 million reduction of the carrying value of
our oil and gas properties in Russia, offset by a
$10 million deferred income tax benefit.
During the second quarter of 2006, we drilled two unsuccessful
exploratory wells in Brazil and determined that the capitalized
costs related to these two wells should be impaired. Therefore,
in the second quarter of 2006, we recognized a $16 million
impairment of our investment in Brazil equal to the costs to
drill the two dry holes and a proportionate share of
block-related costs. There was no tax benefit related to this
impairment. The two wells were unrelated to our Polvo
development project in Brazil.
Other
Income, Net
The following schedule includes the components of other income
between 2006 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Interest and dividend income
|
|
$
|
75
|
|
|
$
|
89
|
|
|
$
|
100
|
|
Hurricane insurance proceeds
|
|
|
162
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
(13
|
)
|
|
|
9
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
224
|
|
|
$
|
98
|
|
|
$
|
115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and dividend income decreased from 2007 to 2008
primarily due to a decrease in interest rates, as well as a
decrease in dividends received on our investment in Chevron
common stock. Interest and dividend income decreased from 2006
to 2007 primarily due to a decrease in income-earning cash and
investment balances, partially offset by an increase in the
dividend rate on our investment in Chevron common stock.
We suffered insured damages in the third quarter of 2005 related
to hurricanes that struck the Gulf of Mexico. During 2006 and
2007, we received $480 million as a full settlement of the
amount due from our primary insurers and certain of our
secondary insurers. During the fourth quarter of 2008, we
received $106 million as full settlement of the amount due
from our remaining secondary insurers. Our claims under our then
existing insurance arrangements included both physical damages
and business interruption claims. As of December 31, 2008,
we had utilized $424 million of these proceeds as
reimbursement of repair costs and deductible amounts, resulting
in excess recoveries. The $162 million of excess recoveries
was recorded as other income during 2008.
Income
Taxes
The following table presents our total income tax (benefit)
expense related to continuing operations and a reconciliation of
our effective income tax rate to the U.S. statutory income
tax rate for each of the past three years. The primary factors
causing our effective rates to vary from 2006 to 2008, and
differ from the U.S. statutory rate, are discussed below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Total income tax (benefit) expense (In millions)
|
|
$
|
(954
|
)
|
|
$
|
1,078
|
|
|
$
|
936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate
|
|
|
(35
|
)%
|
|
|
35
|
%
|
|
|
35
|
%
|
Repatriations and tax policy election changes
|
|
|
8
|
%
|
|
|
|
|
|
|
|
|
Canadian statutory rate reductions
|
|
|
|
|
|
|
(6
|
)%
|
|
|
(7
|
)%
|
Texas income-based tax
|
|
|
|
|
|
|
|
|
|
|
1
|
%
|
Other, primarily taxation on foreign operations
|
|
|
3
|
%
|
|
|
(3
|
)%
|
|
|
(3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax (benefit) expense rate
|
|
|
(24
|
)%
|
|
|
26
|
%
|
|
|
26
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For 2008, our effective income tax rate differed from the
U.S. statutory income tax rate largely due to two related
factors. First, during 2008, we repatriated $2.6 billion
from certain foreign subsidiaries to the
47
United States. Second, we made certain tax policy election
changes in the second quarter of 2008 to minimize the taxes we
otherwise would pay for the cash repatriations, as well as the
taxable gains associated with the sales of assets in West
Africa. As a result of the repatriation and tax policy election
changes, we recognized additional tax expense of
$307 million during 2008. Of the $307 million,
$290 million was recognized as current income tax expense,
and $17 million was recognized as deferred tax expense.
Excluding the $307 million of additional tax expense, our
effective income tax benefit rate would have been 32% for 2008.
In 2008, 2007 and 2006, deferred income taxes were reduced
$7 million, $261 million and $243 million,
respectively, due to successive Canadian statutory rate
reductions that were enacted in each such year.
In 2006, deferred income taxes increased $39 million due to
the effect of a new income-based tax enacted by the state of
Texas that replaced a previous franchise tax. The new tax was
effective January 1, 2007.
Earnings
From Discontinued Operations
Our discontinued operations consist of our operations in Egypt
and West Africa, including Equatorial Guinea, Cote
dIvoire, Gabon and other countries in the region.
In October 2007, we completed the sale of our Egyptian
operations and received proceeds of $341 million. As a
result of this sale, we recognized a $90 million after-tax
gain in the fourth quarter of 2007.
In the second quarter of 2008, we sold our assets and terminated
our operations in certain West African countries, consisting
primarily of Equatorial Guinea and Gabon. As a result of the
sales, we recognized gains totaling $736 million
($674 million after income taxes) in 2008 from proceeds of
$2.4 billion ($1.7 billion net of income taxes and
purchase price adjustments).
In the third quarter of 2008, we sold our assets and terminated
our operations in Cote dIvoire. As a result of this sale,
we recognized a gain of $83 million ($95 million after
income taxes) in 2008 from proceeds of $205 million
($163 million net of income taxes and purchase price
adjustments).
With the Cote dIvoire transaction, we completed the
divestiture of all our oil and gas producing properties in
Africa. The Africa divestitures generated just over
$3.0 billion of sales proceeds. After income taxes and
purchase price adjustments, such proceeds totaled
$2.2 billion and generated after-tax gains of
$0.8 billion.
Following are the components of earnings from discontinued
operations between 2006 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Earnings from discontinued operations before income taxes
|
|
$
|
1,131
|
|
|
$
|
696
|
|
|
$
|
464
|
|
Income tax expense
|
|
|
200
|
|
|
|
236
|
|
|
|
252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations
|
|
$
|
931
|
|
|
$
|
460
|
|
|
$
|
212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 vs. 2007 Earnings from discontinued operations
increased $471 million in 2008. Earnings in 2008 included
$769 million of after-tax divestiture gains as discussed
above. This was $679 million more than the $90 million
after-tax gain from the sale of our Egyptian operations in 2007.
The increase in 2008 was partially offset by a decrease of
$212 million from reduced earnings due to the timing of the
2008 and 2007 divestitures.
2007 vs. 2006 Earnings from discontinued operations
increased $248 million in 2007. In addition to variances
caused by changes in production volumes and realized prices, our
earnings from discontinued operations in 2007 were impacted by
other significant factors. Pursuant to accounting rules for
discontinued operations, we ceased recording DD&A in
November 2006 related to our Egyptian operations and in January
2007 related to our West African operations. This reduction in
DD&A caused earnings from discontinued operations to
increase $119 million in 2007. Earnings in 2007 also
benefited from the $90 million gain from the sale of our
Egyptian operations.
48
In addition, earnings from discontinued operations increased
$90 million in 2007 due to the net effect of reductions in
carrying value in 2006 and 2007. Our earnings in 2007 were
reduced by $13 million from these reductions, compared to
$103 million of reductions recorded in 2006. Due to
unsuccessful drilling activities in Nigeria, in the first
quarter of 2006, we recognized an $85 million impairment of
our investment in Nigeria equal to the costs to drill two dry
holes and a proportionate share of block-related costs. There
was no income tax benefit related to this impairment. As a
result of unsuccessful exploratory activities in Egypt during
2006, the net book value of our Egyptian oil and gas properties,
less related deferred income taxes, exceeded the ceiling by
$18 million as of the end of September 30, 2006.
Therefore, in 2006 we recognized an $18 million after-tax
loss ($31 million pre-tax). In the second quarter of 2007,
based on drilling activities in Nigeria, we recognized a
$13 million after-tax loss ($64 million pre-tax).
Capital
Resources, Uses and Liquidity
The following discussion of capital resources, uses and
liquidity should be read in conjunction with the consolidated
financial statements included in Financial Statements and
Supplementary Data.
Sources
and Uses of Cash
The following table presents the sources and uses of our cash
and cash equivalents from 2006 to 2008. The table presents
capital expenditures on a cash basis. Therefore, these amounts
differ from the amounts of capital expenditures, including
accruals that are referred to elsewhere in this document.
Additional discussion of these items follows the table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Sources of cash and cash equivalents:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating cash flow continuing operations
|
|
$
|
9,273
|
|
|
$
|
6,162
|
|
|
$
|
5,374
|
|
Sales of property and equipment
|
|
|
117
|
|
|
|
76
|
|
|
|
40
|
|
Net credit facility borrowings
|
|
|
|
|
|
|
1,450
|
|
|
|
|
|
Net commercial paper borrowings
|
|
|
1
|
|
|
|
|
|
|
|
1,808
|
|
Net decrease in short-term investments
|
|
|
250
|
|
|
|
202
|
|
|
|
106
|
|
Stock option exercises
|
|
|
116
|
|
|
|
91
|
|
|
|
73
|
|
Proceeds from exchange of Chevron stock
|
|
|
280
|
|
|
|
|
|
|
|
|
|
Cash received from discontinued operations
|
|
|
1,898
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
60
|
|
|
|
44
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sources of cash and cash equivalents
|
|
|
11,995
|
|
|
|
8,025
|
|
|
|
7,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(9,375
|
)
|
|
|
(6,158
|
)
|
|
|
(7,346
|
)
|
Net credit facility repayments
|
|
|
(1,450
|
)
|
|
|
|
|
|
|
|
|
Net commercial paper repayments
|
|
|
|
|
|
|
(804
|
)
|
|
|
|
|
Debt repayments
|
|
|
(1,031
|
)
|
|
|
(567
|
)
|
|
|
(862
|
)
|
Repurchases of common stock
|
|
|
(665
|
)
|
|
|
(326
|
)
|
|
|
(253
|
)
|
Redemption of preferred stock
|
|
|
(150
|
)
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
(289
|
)
|
|
|
(259
|
)
|
|
|
(209
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total uses of cash and cash equivalents
|
|
|
(12,960
|
)
|
|
|
(8,114
|
)
|
|
|
(8,670
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease from continuing operations
|
|
|
(965
|
)
|
|
|
(89
|
)
|
|
|
(1,233
|
)
|
Increase from discontinued operations, net of distributions to
continuing operations
|
|
|
92
|
|
|
|
655
|
|
|
|
370
|
|
Effect of foreign exchange rates
|
|
|
(116
|
)
|
|
|
51
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
$
|
(989
|
)
|
|
$
|
617
|
|
|
$
|
(850
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
384
|
|
|
$
|
1,373
|
|
|
$
|
756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments at end of year
|
|
$
|
|
|
|
$
|
372
|
|
|
$
|
574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49
Operating
Cash Flow Continuing Operations
Net cash provided by operating activities (operating cash
flow) continued to be our primary source of capital and
liquidity in 2008. Changes in operating cash flow are largely
due to the same factors that affect our net earnings, with the
exception of those earnings changes due to such noncash expenses
as DD&A, financial instrument fair value changes, property
impairments and deferred income taxes. As a result, our
operating cash flow increased 50% during 2008 primarily due to
the $3.0 billion increase in oil, gas and NGL revenues, net
of commodity hedge settlements, as discussed in the
Results of Operations section of this report.
During 2008, 2007 and 2006, our capital expenditures were
primarily funded by our operating cash flow. In 2006, we used a
combination of commercial paper borrowings and proceeds from the
sale of short-term investments to fund the $2.0 billion
Chief acquisition in June 2006.
Other
Sources of Cash
As needed, we utilize cash on hand and access our credit
facilities and commercial paper program as sources of cash to
supplement the liquidity provided by our operating cash flow.
Additionally, we sometimes acquire short-term investments to
maximize our income on available cash balances. As needed, we
may reduce such short-term investment balances to further
supplement our operating cash flow.
During 2008, we reduced our short-term investment balances by
$250 million. We also received $280 million from the
exchange of our investment in Chevron common stock,
$117 million from the sale of non-oil and gas property and
equipment and $116 million from stock option exercises.
Another significant source of cash was our African divestiture
program. In the second and third quarters of 2008, we received
$2.6 billion in proceeds ($1.9 billion net of income
taxes and purchase price adjustments) from sales of assets
located in Equatorial Guinea and other West African countries.
Also, in conjunction with these asset sales, we repatriated an
additional $2.6 billion of earnings from certain foreign
subsidiaries to the United States.
We used these combined sources of cash in 2008 to fund debt
repayments, common stock repurchases, redemptions of preferred
stock and dividends on common and preferred stock.
During 2007, we borrowed $1.5 billion under our unsecured
revolving line of credit and reduced our short-term investment
balances by $202 million. We also received
$341 million of proceeds from the sale of our Egyptian
operations. These sources of cash were used primarily to fund
net commercial paper repayments, long-term debt repayments,
common stock repurchases and dividends on common and preferred
stock.
During 2006, we borrowed $1.8 billion under our commercial
paper program and reduced our short-term investment balances by
$106 million. These sources of cash were largely used to
fund the $2.0 billion acquisition of Chief in June 2006.
Also during 2006, we supplemented operating cash flow with cash
on hand, which was used to fund scheduled long-term debt
maturities, common stock repurchases and dividends on common and
preferred stock.
Capital
Expenditures
Following are the components of our capital expenditures for the
years ended 2008, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
U.S. Onshore
|
|
$
|
5,618
|
|
|
$
|
3,280
|
|
|
$
|
4,477
|
|
U.S. Offshore
|
|
|
1,157
|
|
|
|
687
|
|
|
|
572
|
|
Canada
|
|
|
1,459
|
|
|
|
1,232
|
|
|
|
1,492
|
|
International
|
|
|
515
|
|
|
|
439
|
|
|
|
274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exploration and development
|
|
|
8,749
|
|
|
|
5,638
|
|
|
|
6,815
|
|
Midstream
|
|
|
452
|
|
|
|
370
|
|
|
|
356
|
|
Other
|
|
|
174
|
|
|
|
150
|
|
|
|
175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exploration and development
|
|
$
|
9,375
|
|
|
$
|
6,158
|
|
|
$
|
7,346
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50
Our capital expenditures consist of amounts related to our oil
and gas exploration and development operations, our midstream
operations and other corporate activities. The vast majority of
our capital expenditures are for the acquisition, drilling or
development of oil and gas properties, which totaled
$8.7 billion, $5.6 billion and $6.8 billion in
2008, 2007 and 2006, respectively. The 2008 capital expenditures
include $2.6 billion related to acquisitions of properties
in Texas, Louisiana, Oklahoma and Canada. The 2006 capital
expenditures include $2.0 billion related to the
acquisition of the Chief properties. Excluding the effect of
these acquisitions, the increase in capital expenditures from
2006 to 2008 was due to increased drilling activities in the
Barnett Shale, Gulf of Mexico, Carthage, Cana, Woodford Shale,
Groesbeck and Washakie areas of the United States, the
Lloydminster and Jackfish projects in Canada, and in the Polvo
development in Brazil. Expenditures also increased due to
inflationary pressure driven by increased competition for field
services.
Our capital expenditures for our midstream operations are
primarily for the construction and expansion of natural gas
processing plants, natural gas pipeline systems and oil
pipelines. These midstream facilities exist primarily to support
our oil and gas development operations. The majority of our
midstream expenditures from 2006 to 2008 were related to
development activities in the Barnett Shale, the Woodford Shale
in southeastern Oklahoma and Jackfish in Canada.
Debt
Repayments
During 2008, we repaid $1.5 billion in outstanding credit
facility borrowings primarily with proceeds received from the
sales of assets under our African divestiture program. Also
during 2008, virtually all holders of exchangeable debentures
exercised their option to exchange their debentures for shares
of Chevron common stock owned by us. The debentures matured on
August 15, 2008. In lieu of delivering our shares of
Chevron common stock, we exercised our option to pay the
exchanging debenture holders cash totaling $1.0 billion.
This amount included the retirement of debentures with a book
value of $652 million and a $379 million payment of
the related embedded derivative option.
During 2007, we repaid the $400 million 4.375% notes,
which matured on October 1, 2007. Also during 2007, certain
holders of exchangeable debentures exercised their option to
exchange their debentures for shares of Chevron common stock
prior to the debentures August 15, 2008 maturity
date. In lieu of delivering shares of Chevron common stock, we
exercised our option to pay the exchanging debenture holders an
amount of cash equal to the market value of Chevron common
stock. We paid $167 million in cash to exchangeable
debenture holders who exercised their exchange rights. This
amount included the retirement of debentures with a book value
of $105 million and a $62 million payment of the
related embedded derivative option.
During 2006, we retired the $500 million 2.75% notes
and the $178 million ($200 million Canadian)
6.55% senior notes. We also repaid $180 million of
debt acquired in the Chief acquisition.
Repurchases
of Common Stock
During the three-year period ended December 31, 2008, we
repurchased 14.8 million shares at a total cost of
$1.2 billion, or $83.98 per share, under various repurchase
programs. During 2008, we repurchased 6.5 million shares at
a cost of $665 million, or $102.56 per share. During 2007,
we repurchased 4.1 million shares at a cost of
$326 million, or $79.80 per share. During 2006, we
repurchased 4.2 million shares at a cost of
$253 million, or $59.61 per share.
Redemption
of Preferred Stock
On June 20, 2008, we redeemed all 1.5 million
outstanding shares of our 6.49% Series A cumulative
preferred stock. Each share of preferred stock was redeemed for
cash at a redemption price of $100 per share, plus accrued and
unpaid dividends up to the redemption date.
51
Dividends
Our common stock dividends were $284 million (or a
quarterly rate of $0.16 per share), $249 million (or a
quarterly rate of $0.14 per share) and $199 million (or a
quarterly rate of $0.1125) in 2008, 2007 and 2006, respectively.
Common dividends increased primarily due to the higher quarterly
dividend rates.
We also paid $5 million of preferred stock dividends in
2008 and $10 million of preferred stock dividends in both
2007 and 2006. The decrease in the preferred dividends in 2008
was due to the redemption of our preferred stock in the second
quarter of 2008.
Liquidity
Historically, our primary source of capital and liquidity has
been operating cash flow. During 2008, we repatriated earnings
from certain foreign subsidiaries to the United States in
conjunction with the divestitures of our assets in West Africa.
Subsequent to these repatriations, we do not expect to
repatriate similar earnings from our historical operations in
the foreseeable future. Additionally, we maintain revolving
lines of credit and a commercial paper program, which can be
accessed as needed to supplement operating cash flow. Other
available sources of capital and liquidity include the issuance
of equity securities and long-term debt. We expect the
combination of these sources of capital will be adequate to fund
future capital expenditures, debt repayments and other
contractual commitments as discussed later in this section.
Operating
Cash Flow
Our operating cash flow has increased approximately 73% since
2006, reaching a total of $9.3 billion in 2008. We expect
operating cash flow to continue to be our primary source of
liquidity. Our operating cash flow is sensitive to many
variables, the most volatile of which is pricing of the oil, gas
and NGLs we produce.
Commodity Prices Prices for oil, gas and NGLs
are determined primarily by prevailing market conditions.
Regional and worldwide economic activity, weather and other
substantially variable factors influence market conditions for
these products. These factors, which are difficult to predict,
create volatility in oil, gas and NGL prices and are beyond our
control. Although we expect this volatility to continue
throughout 2009, we expect 2009 oil, gas and NGL prices will be
noticeably lower than those for 2008. The corresponding
reduction in our operating cash flow will require us to scale
back certain uses of cash during 2009 compared to 2008,
including most notably our capital expenditures.
To mitigate some of the risk inherent in prices, we have
utilized various price collars to set minimum and maximum prices
on a portion of our production. We have also utilized various
price swap contracts and fixed-price physical delivery contracts
to fix the price of a portion of our future oil and gas
production. Based on contracts in place as of February 16,
2009, in 2009 approximately 10% of our estimated gas production
is subject to either price collars or fixed-price contracts. The
key terms of these contracts are summarized in
Item 7A. Quantitative and Qualitative Disclosures
about Market Risk.
Commodity prices can also affect our operating cash flow through
an indirect effect on operating expenses. Significant commodity
price increases, as experienced in recent years, can lead to an
increase in drilling and development activities. As a result,
the demand and cost for people, services, equipment and
materials may also increase, causing a negative impact on our
cash flow. However, the inverse is also true during periods of
depressed commodity prices such as what we are currently
experiencing.
Interest Rates Our operating cash flow can
also be sensitive to interest rate fluctuations. As of
January 31, 2009, we had long-term debt of
$6.2 billion. This included $6.0 billion of fixed-rate
debt and $0.2 billion of variable-rate commercial paper
borrowings. The fixed-rate debt bears interest at an overall
weighted average rate of 7.23%. We also have interest rate swaps
to mitigate a portion of the fair value effects of interest rate
fluctuations on our fixed-rate debt. Under the terms of these
swaps, we receive a fixed rate and pay a variable rate on a
total notional amount of $1.05 billion. Including the
effects of these swaps, the weighted-average interest rate
related to our fixed-rate debt was 6.64% as of January 31,
2009. The key terms of these interest rate swaps are included in
Item 7A. Quantitative and Qualitative Disclosures of
Market Risk.
52
Credit Losses Our operating cash flow is also
exposed to credit risk in a variety of ways. We are exposed to
the credit risk of the customers who purchase our oil, gas and
NGL production. We are also exposed to credit risk related to
the collection of receivables from our joint-interest partners
for their proportionate share of expenditures made on projects
we operate. We are also exposed to the credit risk of
counterparties to our derivative financial contracts as
discussed previously in this report.
The recent deterioration of the global financial and capital
markets, combined with the drop in commodity prices, has
increased our credit risk exposure. However, we utilize a
variety of mechanisms to limit our exposure to the credit risks
of our customers, partners and counterparties. Such mechanisms
include, under certain conditions, prepayment requirements for
commodity sales and collateral posting requirements in our
existing derivative contracts.
Credit
Availability
We have two revolving lines of credit and a commercial paper
program that we intend to access during 2009 to provide
liquidity. Although we are reducing our planned 2009 capital
expenditures, we anticipate our operating cash flow in 2009 will
be approximately $1.0 billion less than our capital
expenditures due to significantly lower commodity prices.
We have a $2.65 billion syndicated, unsecured revolving
line of credit (the Senior Credit Facility). The
maturity date for $2.15 billion of the Senior Credit
Facility is April 7, 2013. The maturity date for the
remaining $0.5 billion is April 7, 2012. All amounts
outstanding will be due and payable on the respective maturity
dates unless the maturity is extended. Prior to each April 7
anniversary date, we have the option to extend the maturity of
the Senior Credit Facility for one year, subject to the approval
of the lenders. The Senior Credit Facility includes a revolving
Canadian subfacility in a maximum amount of
U.S. $500 million.
Amounts borrowed under the Senior Credit Facility may, at our
election, bear interest at various fixed rate options for
periods of up to twelve months. Such rates are generally less
than the prime rate. However, we may elect to borrow at the
prime rate. As of January 31, 2009, there were no
borrowings under the Senior Credit Facility.
On November 5, 2008, we established a new $700 million
364-day,
syndicated, unsecured revolving senior credit facility (the
Short-Term Facility). The Short-Term Facility
provides us with incremental liquidity for near-term capital
expenditures.
The Short-Term Facility matures on November 3, 2009. On the
maturity date, all amounts outstanding will be due and payable
at that time. Amounts borrowed under the Short-Term Facility
bear interest at various fixed rate options for periods of up to
12 months. Such rates are generally based on LIBOR or the
prime rate. As of January 31, 2009, there were no
borrowings under the Short-Term Facility.
We also have access to short-term credit under our commercial
paper program. Total borrowings under the commercial paper
program may not exceed $2.85 billion. Also, any borrowings
under the commercial paper program reduce available capacity
under the Senior Credit Facility or the Short-Term Facility on a
dollar-for-dollar basis. Commercial paper debt generally has a
maturity of between one and 90 days, although it can have a
maturity of up to 365 days, and bears interest at rates
agreed to at the time of the borrowing. The interest rate is
based on a standard index such as the Federal Funds Rate, LIBOR,
or the money market rate as found on the commercial paper
market. As of January 31, 2009, we had $0.2 billion of
commercial paper debt outstanding at an average rate of 3.33%.
The Senior Credit Facility and Short-Term Facility contain only
one material financial covenant. This covenant requires our
ratio of total funded debt to total capitalization to be less
than 65%. The credit agreement contains definitions of total
funded debt and total capitalization that include adjustments to
the respective amounts reported in the consolidated financial
statements. Also, total capitalization is adjusted to add back
noncash financial writedowns such as full cost ceiling
impairments or goodwill impairments. As of December 31,
2008, we were in compliance with this covenant. Our
debt-to-capitalization ratio at December 31, 2008, as
calculated pursuant to the terms of the agreement, was 18.6%.
53
Our access to funds from the Senior Credit Facility and
Short-Term Facility is not restricted under any material
adverse effect clauses. It is not uncommon for credit
agreements to include such clauses. These clauses can remove the
obligation of the banks to fund the credit line if any condition
or event would reasonably be expected to have a material and
adverse effect on the borrowers financial condition,
operations, properties or business considered as a whole, the
borrowers ability to make timely debt payments, or the
enforceability of material terms of the credit agreement. While
our credit facilities include covenants that require us to
report a condition or event having a material adverse effect,
the obligation of the banks to fund the credit facilities is not
conditioned on the absence of a material adverse effect.
The following schedule summarizes the capacity of our credit
facilities by maturity date, as well as our available capacity
as of January 31, 2009.
|
|
|
|
|
|
|
Amount
|
|
|
|
(In millions)
|
|
|
Senior Credit Facility:
|
|
|
|
|
April 7, 2012 maturity
|
|
$
|
500
|
|
April 7, 2013 maturity
|
|
|
2,150
|
|
|
|
|
|
|
Total Senior Credit Facility
|
|
|
2,650
|
|
Short-Term Facility November 3, 2009 maturity
|
|
|
700
|
|
|
|
|
|
|
Total credit facilities
|
|
|
3,350
|
|
Less:
|
|
|
|
|
Outstanding credit facility borrowings
|
|
|
|
|
Outstanding commercial paper borrowings
|
|
|
176
|
|
Outstanding letters of credit
|
|
|
119
|
|
|
|
|
|
|
Total available capacity
|
|
$
|
3,055
|
|
|
|
|
|
|
Debt
Ratings
We receive debt ratings from the major ratings agencies in the
United States. In determining our debt ratings, the agencies
consider a number of items including, but not limited to, debt
levels, planned asset sales, near-term and long-term production
growth opportunities and capital allocation challenges.
Liquidity, asset quality, cost structure, reserve mix, and
commodity pricing levels are also considered by the rating
agencies. Our current debt ratings are BBB+ with a stable
outlook by both Fitch and Standard & Poors, and
Baa1 with a stable outlook by Moodys.
There are no rating triggers in any of our
contractual obligations that would accelerate scheduled
maturities should our debt rating fall below a specified level.
Our cost of borrowing under our Senior Credit Facility is
predicated on our corporate debt rating. Therefore, even though
a ratings downgrade would not accelerate scheduled maturities,
it would adversely impact the interest rate on any borrowings
under our Senior Credit Facility. Under the terms of the Senior
Credit Facility, a one-notch downgrade would increase the
fully-drawn borrowing costs from LIBOR plus 35 basis points
to a new rate of LIBOR plus 45 basis points. A ratings
downgrade could also adversely impact our ability to
economically access debt markets in the future. As of
December 31, 2008, we were not aware of any potential
ratings downgrades being contemplated by the rating agencies.
Capital
Expenditures
In February 2009, we provided guidance for our 2009 capital
expenditures, which are expected to range from $4.7 billion
to $5.4 billion. This estimate is significantly lower than
our 2008 capital expenditures, which coincides with the
significant decline in current oil, gas and NGL prices, as well
as the near-term price expectations. To a certain degree, the
ultimate timing of these capital expenditures is within our
control. Therefore, if oil and gas prices fluctuate from current
estimates, we could choose to defer a portion of these planned
2009 capital expenditures until later periods, or accelerate
capital expenditures planned for periods
54
beyond 2009 to achieve the desired balance between sources and
uses of liquidity. Based upon current price expectations for
2009 and the commodity price collars and fixed-price contracts
we have in place, we anticipate having adequate capital
resources to fund our 2009 capital expenditures.
Common
Stock Repurchase Programs
We have an ongoing, annual stock repurchase program to minimize
dilution resulting from restricted stock issued to, and options
exercised by, employees. In 2009, the repurchase program
authorizes the repurchase of up to 4.8 million shares or a
cost of $360 million, whichever amount is reached first.
In anticipation of the completion of our West African
divestitures, our Board of Directors approved a separate program
to repurchase up to 50 million shares. This program expires
on December 31, 2009.
In response to the current economic environment and recent
downturn in commodity prices, we have indefinitely suspended
activity under both these programs. As a result, we do not
anticipate repurchasing shares under these programs in the
foreseeable future. Should economic conditions or commodity
prices strengthen, we will consider resumption of share
repurchases under our authorized programs.
Contractual
Obligations
A summary of our contractual obligations as of December 31,
2008, is provided in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less Than
|
|
|
1-3
|
|
|
3-5
|
|
|
More Than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Long-term debt(1)
|
|
$
|
5,817
|
|
|
$
|
177
|
|
|
$
|
2,100
|
|
|
$
|
10
|
|
|
$
|
3,530
|
|
Interest expense(2)
|
|
|
5,392
|
|
|
|
393
|
|
|
|
812
|
|
|
|
520
|
|
|
|
3,667
|
|
Drilling and facility obligations(3)
|
|
|
3,735
|
|
|
|
1,423
|
|
|
|
1,472
|
|
|
|
739
|
|
|
|
101
|
|
Firm transportation agreements(4)
|
|
|
1,994
|
|
|
|
273
|
|
|
|
516
|
|
|
|
421
|
|
|
|
784
|
|
Asset retirement obligations(5)
|
|
|
1,485
|
|
|
|
138
|
|
|
|
282
|
|
|
|
181
|
|
|
|
884
|
|
Lease obligations(6)
|
|
|
833
|
|
|
|
105
|
|
|
|
213
|
|
|
|
206
|
|
|
|
309
|
|
Other(7)
|
|
|
386
|
|
|
|
108
|
|
|
|
81
|
|
|
|
34
|
|
|
|
163
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
19,642
|
|
|
$
|
2,617
|
|
|
$
|
5,476
|
|
|
$
|
2,111
|
|
|
$
|
9,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Long-term debt amounts represent scheduled maturities of our
debt obligations at December 31, 2008, excluding
$24 million of net premiums included in the carrying value
of debt. Additionally, as of December 31, 2008, we had
$1.0 billion of outstanding commercial paper borrowings
that were due within one year. In January 2009, we issued
$500 million of 5.625% senior notes due 2014 and
$700 million of 6.30% senior notes due 2019. The
proceeds from the senior notes were used to repay our
outstanding commercial paper borrowings. Therefore, the
$1.0 billion of commercial paper outstanding as of
December 31, 2008 is presented in the more than
5 years column. |
|
(2) |
|
Interest expense related to our fixed-rate debt represents the
scheduled cash payments. Interest related to our variable-rate
commercial paper borrowings was calculated using the fixed-rates
and scheduled cash payments of the senior notes which were
issued in January 2009 to repay our outstanding commercial paper
as discussed in note (1) above. |
|
(3) |
|
Drilling and facility obligations represent contractual
agreements with third-party service providers to procure
drilling rigs and other related services for developmental and
exploratory drilling and facilities construction. Included in
the $3.7 billion total is $1.7 billion that relates to
long-term contracts for three deepwater drilling rigs and
certain other contracts for onshore drilling and facility
obligations in which drilling or facilities construction has not
commenced. The $1.7 billion represents the gross commitment
under these contracts. Our ultimate payment for these
commitments will be reduced by the amounts billed to our working
interest partners. Payments for these commitments, net of
amounts billed to partners, will be capitalized as a component
of oil and gas properties. |
55
|
|
|
(4) |
|
Firm transportation agreements represent ship or pay
arrangements whereby we have committed to ship certain volumes
of oil, gas and NGLs for a fixed transportation fee. We have
entered into these agreements to aid the movement of our
production to market. We expect to have sufficient production to
utilize the majority of these transportation services. |
|
(5) |
|
Asset retirement obligations represent estimated discounted
costs for future dismantlement, abandonment and rehabilitation
costs. These obligations are recorded as liabilities on our
December 31, 2008 balance sheet. |
|
(6) |
|
Lease obligations consist of operating leases for office space
and equipment, an offshore platform spar and FPSOs. Office
and equipment leases represent non-cancelable leases for office
space and equipment used in our daily operations. |
|
|
|
We have an offshore platform spar that is being used in the
development of the Nansen field in the Gulf of Mexico. This spar
is subject to a
20-year
lease and contains various options whereby we may purchase the
lessors interests in the spars. We have guaranteed that
the spar will have a residual value at the end of the term equal
to at least 10% of the fair value of the spar at the inception
of the lease. The total guaranteed value is $14 million in
2022. However, such amount may be reduced under the terms of the
lease agreements. In 2005, we sold our interests in the Boomvang
field in the Gulf of Mexico, which has a spar lease with terms
similar to those of the Nansen lease. As a result of the sale,
we are subleasing the Boomvang spar. The table above does not
include any amounts related to the Boomvang spar lease. However,
if the sublessee were to default on its obligation, we would
continue to be obligated to pay the periodic lease payments and
any guaranteed value required at the end of the term. |
|
|
|
We also lease three FPSOs that are related to the Panyu
project offshore China, the Polvo project offshore Brazil and
the Cascade project offshore the Gulf of Mexico. The Panyu FPSO
lease term expires in September 2009. The Polvo FPSO lease
term expires in 2014. The Cascade FPSO lease term expires in
2015. |
|
(7) |
|
These amounts include $260 million related to uncertain tax
positions. Expected pension funding obligations have not been
included in this table, but are presented and discussed in the
section immediately below. |
Pension
Funding and Estimates
Funded Status. As compared to the projected
benefit obligation, our qualified and nonqualified defined
benefit plans were underfunded by $501 million and
$230 million at December 31, 2008 and 2007,
respectively. A detailed reconciliation of the 2008 changes to
our underfunded status is included in Note 8 to the
accompanying consolidated financial statements. Of the
$501 million underfunded status at the end of 2008,
$211 million is attributable to various nonqualified
defined benefit plans that have no plan assets. However, we have
established certain trusts to fund the benefit obligations of
such nonqualified plans. As of December 31, 2008, these
trusts had investments with a fair value of $50 million.
The value of these trusts is included in noncurrent other assets
in our accompanying consolidated balance sheets.
As compared to the accumulated benefit obligation, our qualified
defined benefit plans were underfunded by $209 million at
December 31, 2008. The accumulated benefit obligation
differs from the projected benefit obligation in that the former
includes no assumption about future compensation levels.
Our funding policy regarding the qualified defined benefit plans
is to contribute the amounts necessary for the plans
assets to approximately equal the present value of benefits
earned by the participants, as calculated in accordance with the
provisions of the Pension Protection Act (PPA).
During 2008, investment losses significantly reduced the value
of our plans assets. This decrease was the primary
contributor to the significant decrease in the funded status of
our pension plans during 2008. The 2008 investment losses,
combined with our target funding levels, will cause our 2009
contributions to be higher than those made in recent years. We
estimate we will contribute up to approximately
$173 million to our qualified pension plans during 2009.
However, actual contributions may be less than this amount.
Pension Estimate Assumptions. Our pension
expense is recognized on an accrual basis over employees
approximate service periods and is impacted by funding decisions
or requirements. We recognized expense for our defined benefit
pension plans of $61 million, $41 million and
$31 million in 2008, 2007 and 2006,
56
respectively. We estimate that our pension expense will
approximate $114 million in 2009. Should our actual 2009
contributions vary significantly from our current estimate of
$173 million, our actual 2009 pension expense could vary
from this estimate.
The calculation of pension expense and pension liability
requires the use of a number of assumptions. Changes in these
assumptions can result in different expense and liability
amounts, and actual experience can differ from the assumptions.
We believe that the two most critical assumptions affecting
pension expense and liabilities are the expected long-term rate
of return on plan assets and the assumed discount rate.
We assumed that our plan assets would generate a long-term
weighted average rate of return of 7.25% and 8.40% at
December 31, 2008 and 2007, respectively. We developed
these expected long-term rate of return assumptions by
evaluating input from external consultants and economists as
well as long-term inflation assumptions. The expected long-term
rate of return on plan assets is based on a target allocation of
investment types in such assets. At December 31, 2008, the
target investment allocation for our plan assets is 30%
U.S. large cap equity securities; 15% U.S. small cap
equity securities, equally allocated between growth and value;
15% international equity securities, equally allocated between
growth and value; and 40% debt securities. The target investment
allocation for our plan assets at December 31, 2007, was
50% U.S. large cap equity securities; 15% U.S. small
cap equity securities, equally allocated between growth and
value; 15% international equity securities, equally allocated
between growth and value; and 20% debt securities. We expect our
long-term asset allocation on average to approximate the
targeted allocation. We regularly review our actual asset
allocation and periodically rebalance the investments to the
targeted allocation when considered appropriate.
Pension expense increases as the expected rate of return on plan
assets decreases. A decrease in our long-term rate of return
assumption of 100 basis points (from 7.25% to 6.25%) would
increase the expected 2009 pension expense by $5 million.
We discounted our future pension obligations using a weighted
average rate of 6.00% and 6.22% at December 31, 2008 and
2007, respectively. The discount rate is determined at the end
of each year based on the rate at which obligations could be
effectively settled, considering the expected timing of future
cash flows related to the plans. This rate is based on
high-quality bond yields, after allowing for call and default
risk. We consider high quality corporate bond yield indices,
such as Moodys Aa, when selecting the discount rate.
The pension liability and future pension expense both increase
as the discount rate is reduced. Lowering the discount rate by
25 basis points (from 6.00% to 5.75%) would increase our
pension liability at December 31, 2008, by
$31 million, and increase estimated 2009 pension expense by
$5 million.
At December 31, 2008, we had net actuarial losses of
$440 million, which will be recognized as a component of
pension expense in future years. These losses are primarily due
to the large investment losses on plan assets in 2008,
reductions in the discount rate since 2001 and increases in
participant wages. We estimate that approximately
$45 million and $41 million of the unrecognized
actuarial losses will be included in pension expense in 2009 and
2010, respectively. The $45 million estimated to be
recognized in 2009 is a component of the total estimated 2009
pension expense of $114 million referred to earlier in this
section.
Future changes in plan asset returns, assumed discount rates and
various other factors related to the participants in our defined
benefit pension plans will impact future pension expense and
liabilities. We cannot predict with certainty what these factors
will be in the future.
Contingencies
and Legal Matters
For a detailed discussion of contingencies and legal matters,
see Note 10 of the accompanying consolidated financial
statements.
Critical
Accounting Policies and Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported
57
amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements,
and the reported amounts of revenues and expenses during the
reporting period. Actual amounts could differ from these
estimates, and changes in these estimates are recorded when
known.
The critical accounting policies used by management in the
preparation of our consolidated financial statements are those
that are important both to the presentation of our financial
condition and results of operations and require significant
judgments by management with regard to estimates used. Our
critical accounting policies and significant judgments and
estimates related to those policies are described below. We have
reviewed these critical accounting policies with the Audit
Committee of our Board of Directors.
Full
Cost Ceiling Calculations
Policy
Description
We follow the full cost method of accounting for our oil and gas
properties. The full cost method subjects companies to quarterly
calculations of a ceiling, or limitation on the
amount of properties that can be capitalized on the balance
sheet. The ceiling limitation is the discounted estimated
after-tax future net revenues from proved oil and gas
properties, excluding future cash outflows associated with
settling asset retirement obligations included in the net book
value of oil and gas properties, plus the cost of properties not
subject to amortization. If our net book value of oil and gas
properties, less related deferred income taxes, is in excess of
the calculated ceiling, the excess must be written off as an
expense, except as discussed in the following paragraph. The
ceiling limitation is imposed separately for each country in
which we have oil and gas properties. 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.
If, subsequent to the end of the quarter but prior to the
applicable financial statements being published, prices increase
to levels such that the ceiling would exceed the costs to be
recovered, a writedown otherwise indicated at the end of the
quarter is not required to be recorded. A writedown indicated at
the end of a quarter is also not required if the value of
additional reserves proved up on properties after the end of the
quarter but prior to the publishing of the financial statements
would result in the ceiling exceeding the costs to be recovered,
as long as the properties were owned at the end of the quarter.
Judgments
and Assumptions
The discounted present value of future net revenues for our
proved oil, gas and NGL reserves is a major component of the
ceiling calculation, and represents the component that requires
the most subjective judgments. Estimates of reserves are
forecasts based on engineering data, projected future rates of
production and the timing of future expenditures. The process of
estimating oil, gas and NGL reserves requires substantial
judgment, resulting in imprecise determinations, particularly
for new discoveries. Different reserve engineers may make
different estimates of reserve quantities based on the same
data. Certain of our reserve estimates are prepared or audited
by outside petroleum consultants, while other reserve estimates
are prepared by our engineers. See Note 20 of the
accompanying consolidated financial statements for a summary of
the amount of our reserves that are prepared or audited by
outside petroleum consultants.
The passage of time provides more qualitative information
regarding estimates of reserves, and revisions are made to prior
estimates to reflect updated information. In the past five
years, annual performance revisions to our reserve estimates,
which have been both increases and decreases in individual
years, have averaged less than 2% of the previous years
estimate. However, there can be no assurance that more
significant revisions will not be necessary in the future. If
future significant revisions are necessary that reduce
previously estimated reserve quantities, it could result in a
full cost property writedown. In addition to the impact of the
estimates of proved reserves on the calculation of the ceiling,
estimates of proved reserves are also a significant component of
the calculation of DD&A.
While the quantities of proved reserves require substantial
judgment, the associated prices of oil, gas and NGL reserves,
and the applicable discount rate, that are used to calculate the
discounted present value of the reserves do not require
judgment. The ceiling calculation dictates that a 10% discount
factor be used and that
58
prices and costs in effect as of the last day of the period are
held constant indefinitely. Therefore, the future net revenues
associated with the estimated proved reserves are not based on
our assessment of future prices or costs. Rather, they are based
on such prices and costs in effect as of the end of each quarter
when the ceiling calculation is performed. In calculating the
ceiling, we adjust the end-of-period price by the effect of
derivative contracts in place that qualify for hedge accounting
treatment. This adjustment requires little judgment as the
end-of-period price is adjusted using the contract prices for
such hedges. None of our outstanding derivative contracts at
December 31, 2008 qualified for hedge accounting treatment.
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 gas prices have historically been volatile. On any
particular day at the end of a quarter, prices can be either
substantially higher or lower than our 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 the timing or magnitude of full cost
writedowns. However, considering current and near-term estimates
of oil and gas prices, such writedowns may be more likely to
occur during 2009 than in recent periods.
The SEC recently revised the requirement to use quarter-end
prices to calculate the full cost ceiling. Beginning on
December 31, 2009, the ceiling will be calculated using a
12-month
average price. See Modernization of Oil and Gas
Reporting for more information on the SECs revised
rules.
Derivative
Financial Instruments
Policy
Description
We periodically enter into derivative financial instruments with
respect to a portion of our oil and gas production that hedge
the future prices received. These instruments are used to manage
the inherent uncertainty of future revenues due to oil and gas
price volatility. Our derivative financial instruments include
financial price swaps and costless price collars. Under the
terms of the swaps, we will receive a fixed price for our
production and pay a variable market price to the contract
counterparty. The price collars set a floor and ceiling price
for the hedged production. If the applicable monthly price
indices are outside of the ranges set by the floor and ceiling
prices in the various collars, we will cash-settle the
difference with the counterparty to the collars.
We periodically enter into interest rate swaps to manage our
exposure to interest rate volatility. We use these swaps to
mitigate a portion of the fair value effects of interest rate
fluctuations on our fixed-rate debt. Under the terms of these
swaps, we receive a fixed rate and pay a variable rate on a
total notional amount.
All derivative financial instruments are recognized at their
current fair value as either assets or liabilities in the
balance sheet. Changes in the fair value of these derivative
financial instruments are recorded in the statement of
operations unless specific hedge accounting criteria are met. If
such criteria are met for cash flow hedges, the effective
portion of the change in the fair value is recorded directly to
accumulated other comprehensive income, a component of
stockholders equity, until the hedged transaction occurs.
The ineffective portion of the change in fair value is recorded
in the statement of operations. If such criteria are met for
fair value hedges, the change in the fair value is recorded in
the statement of operations with an offsetting amount recorded
for the change in fair value of the hedged item. Cash
settlements with counterparties to our derivative financial
instruments also increase or decrease earnings at the time of
the settlement.
A derivative financial instrument qualifies for hedge accounting
treatment if we designate the instrument as such on the date the
derivative contract is entered into or the date of a business
combination or other transaction that includes derivative
contracts. Additionally, we must document the relationship
between the
59
hedging instrument and hedged item, as well as the
risk-management objective and strategy for undertaking the
instrument. We must also assess, both at the instruments
inception and on an ongoing basis, whether the derivative is
highly effective in offsetting the change in cash flow of the
hedged item. For derivative financial instruments held during
2008, 2007 and 2006, we chose not to meet the necessary criteria
to qualify our derivative financial instruments for hedge
accounting treatment.
Judgments
and Assumptions
The estimates of the fair values of our derivative instruments
require substantial judgment. We estimate the fair values of our
oil and gas derivative financial instruments primarily by using
internal discounted cash flow calculations. The most significant
variable to our cash flow calculations is our estimate of future
commodity prices. We base our estimate of future prices upon
published forward commodity price curves such as the Inside FERC
Henry Hub forward curve for gas instruments and the NYMEX West
Texas Intermediate forward curve for oil instruments. Another
key input to our cash flow calculations is our estimate of
volatility for these forward curves, which we base primarily
upon implied volatility. The resulting estimated future cash
inflows or outflows over the lives of the contracts are
discounted using LIBOR and money market futures rates for the
first year and money market futures and swap rates thereafter.
These pricing and discounting variables are sensitive to the
period of the contract and market volatility as well as changes
in forward prices and regional price differentials.
We estimate the fair values of our interest rate swap financial
instruments primarily by using internal discounted cash flow
calculations based upon forward interest-rate yields. The most
significant variable to our cash flow calculations is our
estimate of future interest rate yields. We base our estimate of
future yields upon our own internal model that utilizes forward
curves such as the LIBOR or the Federal Funds Rate provided by
third parties. Another key input to our cash flow calculations
is our estimate of volatility for these forward yields, which we
base primarily upon implied volatility. The resulting estimated
future cash inflows or outflows over the lives of the contracts
are discounted using LIBOR and money market futures rates for
the first year and money market futures and swap rates
thereafter. These yield and discounting variables are sensitive
to the period of the contract and market volatility as well as
changes in forward interest rate yields.
From time to time, we validate our valuation techniques by
comparing our internally generated fair value estimates with
those obtained from contract counterparties
and/or
brokers.
In spite of the recent turmoil in the financial markets,
counterparty credit risk has not had a significant effect on our
cash flow calculations and derivative valuations. This is
primarily the result of two factors. First, we have mitigated
our exposure to any single counterparty by contracting with
numerous counterparties. Our commodity derivative contracts are
held with eight separate counterparties, and our interest rate
derivative contracts are held with five separate counterparties.
Second, our derivative contracts generally require cash
collateral to be posted if either our or the counterpartys
credit rating falls below investment grade. The
threshold for collateral posting decreases as the debt rating
falls further below investment grade. Such thresholds generally
range from zero to $50 million for the majority of our
contracts. As of December 31, 2008, the credit ratings of
all our counterparties were investment grade.
Quarterly changes in our derivative fair value estimates have
only a minimal impact on our liquidity, capital resources or
results of operations, as long as the derivative instruments
qualify for hedge accounting treatment. Changes in the fair
values of derivatives that do not qualify for hedge accounting
treatment can have a significant impact on our results of
operations, but generally will not impact our liquidity or
capital resources.
Settlements of derivative instruments, regardless of whether
they qualify for hedge accounting, do have an impact on our
liquidity and results of operations. Generally, if actual market
prices are higher than the price of the derivative instruments,
our net earnings and cash flow from operations will be lower
relative to the results that would have occurred absent these
instruments. The opposite is also true. Additional information
regarding the effects that changes in market prices can have on
our derivative financial instruments, net earnings and cash flow
from operations is included in Item 7A. Quantitative
and Qualitative Disclosures about Market Risk.
60
Business
Combinations
Policy
Description
From our beginning as a public company in 1988 through 2003, we
grew substantially through acquisitions of other oil and gas
companies. Most of these acquisitions have been accounted for
using the purchase method of accounting. Current accounting
pronouncements require the purchase method to be used to account
for any future acquisitions.
Under the purchase method, the acquiring company adds to its
balance sheet the estimated fair values of the acquired
companys assets and liabilities. Any excess of the
purchase price over the fair values of the tangible and
intangible net assets acquired is recorded as goodwill. Goodwill
is assessed for impairment at least annually.
Judgments
and Assumptions
There are various assumptions we make in determining the fair
values of an acquired companys assets and liabilities. The
most significant assumptions, and the ones requiring the most
judgment, involve the estimated fair values of the oil and gas
properties acquired. To determine the fair values of these
properties, we prepare estimates of oil, gas and NGL reserves.
These estimates are based on work performed by our engineers and
that of outside consultants. The judgments associated with these
estimated reserves are described earlier in this section in
connection with the full cost ceiling calculation.
However, there are factors involved in estimating the fair
values of acquired oil, gas and NGL properties that require more
judgment than that involved in the full cost ceiling
calculation. As stated above, the full cost ceiling calculation
applies end-of-period price and cost information to the reserves
to arrive at the ceiling amount. By contrast, the fair value of
reserves acquired in a business combination must be based on our
estimates of future oil, gas and NGL prices. Our estimates of
future prices are based on our own analysis of pricing trends.
These estimates are based on current data obtained with regard
to regional and worldwide supply and demand dynamics such as
economic growth forecasts. They are also based on industry data
regarding gas storage availability, drilling rig activity,
changes in delivery capacity, trends in regional pricing
differentials and other fundamental analysis. Forecasts of
future prices from independent third parties are noted when we
make our pricing estimates.
We estimate future prices to apply to the estimated reserve
quantities acquired, and estimate future operating and
development costs, to arrive at estimates of future net
revenues. For estimated proved reserves, the future net revenues
are then discounted using a rate determined appropriate at the
time of the business combination based upon our cost of capital.
We also apply these same general principles to estimate the fair
value of unproved properties acquired in a business combination.
These unproved properties generally represent the value of
probable and possible reserves. Because of their very nature,
probable and possible reserve estimates are more imprecise than
those of proved reserves. To compensate for the inherent risk of
estimating and valuing unproved reserves, the discounted future
net revenues of probable and possible reserves are reduced by
what we consider to be an appropriate risk-weighting factor in
each particular instance. It is common for the discounted future
net revenues of probable and possible reserves to be reduced by
factors ranging from 30% to 80% to arrive at what we consider to
be the appropriate fair values.
Generally, in our business combinations, the determination of
the fair values of oil and gas properties requires much more
judgment than the fair values of other assets and liabilities.
The acquired companies commonly have long-term debt that we
assume in the acquisition, and this debt must be recorded at the
estimated fair value as if we had issued such debt. However,
significant judgment on our behalf is usually not required in
these situations due to the existence of comparable market
values of debt issued by peer companies.
Except for the 2002 acquisition of Mitchell Energy &
Development Corp., our mergers and acquisitions have involved
other entities whose operations were predominantly in the area
of exploration, development and
61
production activities related to oil and gas properties.
However, in addition to exploration, development and production
activities, Mitchells business also included substantial
marketing and midstream activities. Therefore, a portion of the
Mitchell purchase price was allocated to the fair value of
Mitchells marketing and midstream facilities and
equipment. This consisted primarily of natural gas processing
plants and natural gas pipeline systems.
The Mitchell midstream assets primarily serve gas producing
properties that we also acquired from Mitchell. Therefore,
certain of the assumptions regarding future operations of the
gas producing properties were also integral to the value of the
midstream assets. For example, future quantities of gas
estimated to be processed by natural gas processing plants were
based on the same estimates used to value the proved and
unproved gas producing properties. Future expected prices for
marketing and midstream product sales were also based on price
cases consistent with those used to value the oil and gas
producing assets acquired from Mitchell. Based on historical
costs and known trends and commitments, we also estimated future
operating and capital costs of the marketing and midstream
assets to arrive at estimated future cash flows. These cash
flows were discounted at rates consistent with those used to
discount future net cash flows from oil and gas producing assets
to arrive at our estimated fair value of the marketing and
midstream facilities and equipment.
In addition to the valuation methods described above, we perform
other quantitative analyses to support the indicated value in
any business combination. These analyses include information
related to comparable companies, comparable transactions and
premiums paid.
In a comparable companies analysis, we review the public stock
market trading multiples for selected publicly traded
independent exploration and production companies with comparable
financial and operating characteristics. Such characteristics
are market capitalization, location of proved reserves and the
characterization of those reserves that we deem to be similar to
those of the party to the proposed business combination. We
compare these comparable company multiples to the proposed
business combination company multiples for reasonableness.
In a comparable transactions analysis, we review certain
acquisition multiples for selected independent exploration and
production company transactions and oil and gas asset packages
announced recently. We compare these comparable transaction
multiples to the proposed business combination transaction
multiples for reasonableness.
In a premiums paid analysis, we use a sample of selected
independent exploration and production company transactions in
addition to selected transactions of all publicly traded
companies announced recently, to review the premiums paid to the
price of the target one day, one week and one month prior to the
announcement of the transaction. We use this information to
determine the mean and median premiums paid and compare them to
the proposed business combination premium for reasonableness.
While these estimates of fair value for the various assets
acquired and liabilities assumed have no effect on our liquidity
or capital resources, they can have an effect on the future
results of operations. Generally, the higher the fair value
assigned to both the oil and gas properties and non-oil and gas
properties, the lower future net earnings will be as a result of
higher future depreciation, depletion and amortization expense.
Also, a higher fair value assigned to the oil and gas
properties, based on higher future estimates of oil and gas
prices, will increase the likelihood of a full cost ceiling
writedown in the event that subsequent oil and gas prices drop
below our price forecast that was used to originally determine
fair value. A full cost ceiling writedown would have no effect
on our liquidity or capital resources in that period because it
is a noncash charge, but it would adversely affect results of
operations. As discussed in Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Capital Resources, Uses and
Liquidity, in calculating our debt-to-capitalization ratio
under our credit agreement, total capitalization is adjusted to
add back noncash financial writedowns such as full cost ceiling
property impairments or goodwill impairments.
Our estimates of reserve quantities are one of the many
estimates that are involved in determining the appropriate fair
value of the oil and gas properties acquired in a business
combination. As previously disclosed in our discussion of the
full cost ceiling calculations, during the past five years, our
annual performance revisions to our reserve estimates have
averaged less than 2%. As discussed in the preceding paragraphs,
there
62
are numerous estimates in addition to reserve quantity estimates
that are involved in determining the fair value of oil and gas
properties acquired in a business combination. The
inter-relationship of these estimates makes it impractical to
provide additional quantitative analyses of the effects of
changes in these estimates.
Valuation
of Goodwill
Policy
Description
Goodwill represents the excess of the purchase price of business
combinations over the fair value of the net assets acquired and
is tested for impairment at least annually. The impairment test
requires allocating goodwill and all other assets and
liabilities to assigned reporting units. The fair value of each
reporting unit is estimated and compared to the net book value
of the reporting unit. If the estimated fair value of the
reporting unit is less than the net book value, including
goodwill, then the goodwill is written down to the implied fair
value of the goodwill through a charge to expense.
Judgments
and Assumptions
The annual impairment test requires us to estimate the fair
values of our own assets and liabilities. Because quoted market
prices are not available for Devons reporting units, the
fair values of the reporting units are estimated in a manner
similar to the process described above for a business
combination. Therefore, considerable judgment similar to that
described above in connection with estimating the fair value of
an acquired company in a business combination is also required
to assess goodwill for impairment.
Generally, the higher the fair value assigned to both the oil
and gas properties and non-oil and gas properties, the lower
goodwill would be. A lower goodwill value decreases the
likelihood of an impairment charge. However, unfavorable changes
in reserves or in our price forecast would increase the
likelihood of a goodwill impairment charge. A goodwill
impairment charge would have no effect on liquidity or capital
resources. However, it would adversely affect our results of
operations in that period.
Due to the inter-relationship of the various estimates involved
in assessing goodwill for impairment, it is impractical to
provide quantitative analyses of the effects of potential
changes in these estimates, other than to note the historical
average changes in our reserve estimates previously set forth.
Recently
Issued Accounting Standards Not Yet Adopted
In December 2007, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting
Standards No. 141(R), Business Combinations, which
replaces Statement No. 141. Statement No. 141(R)
retains the fundamental requirements of Statement No. 141
that an acquirer be identified and the acquisition method of
accounting (previously called the purchase method) be used for
all business combinations. Statement No. 141(R)s
scope is broader than that of Statement No. 141, which
applied only to business combinations in which control was
obtained by transferring consideration. By applying the
acquisition method to all transactions and other events in which
one entity obtains control over one or more other businesses,
Statement No. 141(R) improves the comparability of the
information about business combinations provided in financial
reports. Statement No. 141(R) establishes principles and
requirements for how an acquirer recognizes and measures
identifiable assets acquired, liabilities assumed and any
noncontrolling interest in the acquiree, as well as any
resulting goodwill. Statement No. 141(R) applies
prospectively to business combinations for which the acquisition
date is on or after the beginning of the first annual reporting
period beginning on or after December 15, 2008. We will
evaluate how the new requirements of Statement No. 141(R)
would impact any business combinations completed in 2009 or
thereafter.
In December 2007, the FASB also issued Statement of Financial
Accounting Standards No. 160, Noncontrolling Interests
in Consolidated Financial Statements an amendment of
Accounting Research Bulletin No. 51. A
noncontrolling interest, sometimes called a minority interest,
is the portion of equity in a subsidiary not attributable,
directly or indirectly, to a parent. Statement No. 160
establishes accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. Under Statement No. 160,
noncontrolling interests in a subsidiary must be reported as a
component of
63
consolidated equity separate from the parents equity.
Additionally, the amounts of consolidated net income
attributable to both the parent and the noncontrolling interest
must be reported separately on the face of the income statement.
Statement No. 160 is effective for fiscal years beginning
on or after December 15, 2008 and earlier adoption is
prohibited. The adoption of Statement No. 160 will not have
a material impact on our financial statements and related
disclosures.
In December 2008, the FASB issued Staff Position
No. FAS 132(R)-1, Employers Disclosures about
Postretirement Benefit Plan Assets. Staff Position 132(R)-1
amends FASB Statement No. 132 (revised 2003),
Employers Disclosures about Pensions and Other
Postretirement Benefits, to require additional disclosures
about the types of assets and associated risks in an
employers defined benefit pension or other postretirement
plan. Staff Position 132(R)-1 is effective for fiscal years
ending after December 15, 2009. We are evaluating the
impact the adoption of Staff Position 132(R)-1 will have on our
financial statement disclosures. However, our adoption of Staff
Position 132(R)-1 will not affect our current accounting for our
pension and postretirement plans.
Modernization
of Oil and Gas Reporting
In December 2008, the SEC adopted revisions to its required oil
and gas reporting disclosures. The revisions are intended to
provide investors with a more meaningful and comprehensive
understanding of oil and gas reserves. In the three decades that
have passed since adoption of these disclosure items, there have
been significant changes in the oil and gas industry. The
amendments are designed to modernize and update the oil and gas
disclosure requirements to align them with current practices and
changes in technology. In addition, the amendments concurrently
align the SECs full cost accounting rules with the revised
disclosures. The revised disclosure requirements must be
incorporated in registration statements filed on or after
January 1, 2010, and annual reports on
Form 10-K
for fiscal years ending on or after December 31, 2009. A
company may not apply the new rules to disclosures in quarterly
reports prior to the first annual report in which the revised
disclosures are required.
The following amendments have the greatest likelihood of
affecting our reserve disclosures, including the comparability
of our reserves disclosures with those of our peer companies:
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Pricing mechanism for oil and gas reserves estimation
The SECs current rules require proved
reserve estimates to be calculated using prices as of the end of
the period and held constant over the life of the reserves.
Price changes can be made only to the extent provided by
contractual arrangements. The revised rules require reserve
estimates to be calculated using a
12-month
average price. The
12-month
average price will also be used for purposes of calculating the
full cost ceiling limitations. The use of a
12-month
average price rather than a
single-day
price is expected to reduce the impact on reserve estimates and
the full cost ceiling limitations due to short-term volatility
and seasonality of prices.
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Reasonable certainty The SECs current
definition of proved oil and gas reserves incorporate certain
specific concepts such as lowest known hydrocarbons,
which limits the ability to claim proved reserves in the absence
of information on fluid contacts in a well penetration,
notwithstanding the existence of other engineering and
geoscientific evidence. The revised rules amend the definition
to permit the use of new reliable technologies to establish the
reasonable certainty of proved reserves. This revision also
includes provisions for establishing levels of lowest known
hydrocarbons and highest known oil through reliable technology
other than well penetrations.
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The revised rules also amend the definition of proved oil and
gas reserves to include reserves located beyond development
spacing areas that are immediately adjacent to developed spacing
areas if economic producibility can be established with
reasonable certainty. These revisions are designed to permit the
use of alternative technologies to establish proved reserves in
lieu of requiring companies to use specific tests. In addition,
they establish a uniform standard of reasonable certainty that
applies to all proved reserves, regardless of location or
distance from producing wells.
64
Because the revised rules generally expand the definition of
proved reserves, we expect our proved reserve estimates will
increase upon adoption of the revised rules. However, we are not
able to estimate the magnitude of the potential increase at this
time.
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Unproved reserves The SECs current
rules prohibit disclosure of reserve estimates other than proved
in documents filed with the SEC. The revised rules permit
disclosure of probable and possible reserves and provide
definitions of probable reserves and possible reserves.
Disclosure of probable and possible reserves is optional.
However, such disclosures must meet specific requirements.
Disclosures of probable or possible reserves must provide the
same level of geographic detail as proved reserves and must
state whether the reserves are developed or undeveloped.
Probable and possible reserve disclosures must also provide the
relative uncertainty associated with these classifications of
reserves estimations. We have not yet determined whether we will
disclose our probable and possible reserves in documents filed
with the SEC.
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Forward-Looking
Estimates
We are providing our 2009 forward-looking estimates in the
following discussion. These estimates are based on our
examination of historical operating trends, the information used
to prepare our December 31, 2008 reserve reports and other
data in our possession or available from third parties. The
forward-looking estimates in this discussion were prepared
assuming demand, curtailment, producibility and general market
conditions for our oil, gas and NGLs during 2009 will be
substantially similar to those that existed in 2008, unless
otherwise noted. We make reference to the Disclosure
Regarding Forward-Looking Statements at the beginning of
this report. Amounts related to Canadian operations have been
converted to U.S. dollars using a projected average 2009
exchange rate of $0.80 U.S. dollar to $1.00 Canadian dollar.
Operating
Items
Oil, Gas
and NGL Production
Set forth below are our estimates of oil, gas and NGL production
for 2009. We estimate that our combined 2009 oil, gas and NGL
production will total approximately 235 to 241 MMBoe. Of
this total, approximately 97% is estimated to be produced from
reserves classified as proved at December 31,
2008. The following estimates for oil, gas and NGL production
are calculated at the midpoint of the estimated range for total
production.
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Oil
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Gas
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NGLs
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Total
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(MMBbls)
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(Bcf)
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(MMBbls)
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(MMBoe)
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United States Onshore
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12
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676
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25
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149
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United States Offshore
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4
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42
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11
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Canada
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29
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185
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3
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63
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International
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15
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1
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15
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Total
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60
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904
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28
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238
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Oil and
Gas Prices
We expect our 2009 average prices for the oil and gas production
from each of our operating areas to differ from the NYMEX price
as set forth in the following table. The expected ranges for gas
prices are exclusive of the anticipated effects of the gas
financial contracts presented in the Commodity Price Risk
Management section below.
65
The NYMEX price for oil is the monthly average of settled prices
on each trading day for benchmark West Texas Intermediate crude
oil delivered at Cushing, Oklahoma. The NYMEX price for gas is
determined to be the first-of-month South Louisiana Henry Hub
price index as published monthly in Inside FERC.
|
|
|
|
|
|
|
Expected Range of Prices
|
|
|
as a% of NYMEX Price
|
|
|
Oil
|
|
Gas
|
|
United States Onshore
|
|
85% to 95%
|
|
75% to 85%
|
United States Offshore
|
|
95% to 105%
|
|
100% to 110%
|
Canada
|
|
55% to 65%
|
|
83% to 93%
|
International
|
|
85% to 95%
|
|
N/M
|
N/M Not meaningful.
Commodity
Price Risk Management
From time to time, we enter into NYMEX related financial
commodity collar and price swap contracts. Such contracts are
used to manage the inherent uncertainty of future revenues due
to oil and gas price volatility. Although these financial
contracts do not relate to specific production from our
operating areas, they will affect our overall revenues, earnings
and cash flow in 2009.
As of February 3, 2009, our financial commodity contracts
pertaining to 2009 consisted only of gas collars. The key terms
of these contracts are presented in the following table.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor Price
|
|
|
Ceiling Price
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Floor
|
|
|
Average
|
|
|
Ceiling
|
|
|
Average
|
|
|
|
Volume
|
|
|
Range
|
|
|
Price
|
|
|
Range
|
|
|
Price
|
|
Period
|
|
(MMBtu/d)
|
|
|
($/MMBtu)
|
|
|
($/MMBtu)
|
|
|
($/MMBtu)
|
|
|
($/MMBtu)
|
|
|
First Quarter
|
|
|
277,056
|
|
|
$
|
8.00 - $8.50
|
|
|
$
|
8.25
|
|
|
$
|
10.60 - $14.00
|
|
|
$
|
12.02
|
|
Second Quarter
|
|
|
265,000
|
|
|
$
|
8.00 - $8.50
|
|
|
$
|
8.25
|
|
|
$
|
10.60 - $14.00
|
|
|
$
|
12.05
|
|
Third Quarter
|
|
|
265,000
|
|
|
$
|
8.00 - $8.50
|
|
|
$
|
8.25
|
|
|
$
|
10.60 - $14.00
|
|
|
$
|
12.05
|
|
Fourth Quarter
|
|
|
265,000
|
|
|
$
|
8.00 - $8.50
|
|
|
$
|
8.25
|
|
|
$
|
10.60 - $14.00
|
|
|
$
|
12.05
|
|
2009 Average
|
|
|
267,973
|
|
|
$
|
8.00 - $8.50
|
|
|
$
|
8.25
|
|
|
$
|
10.60 - $14.00
|
|
|
$
|
12.05
|
|
To the extent that monthly NYMEX prices in 2009 are outside of
the ranges established by the gas collars, we and the
counterparties to the contracts will settle the difference. Such
settlements will either increase or decrease our revenues for
the period. Also, we will mark-to-market the contracts based on
their fair values throughout 2009. Changes in the
contracts fair values will also be recorded as increases
or decreases to our revenues. The expected ranges of our
realized gas prices as a percentage of NYMEX prices, which are
presented earlier in this report, do not include any estimates
of the impact on our gas prices from monthly settlements or
changes in the fair values of our gas collars.
In January 2009, we entered into an early settlement arrangement
with one of our counterparties. As a result of this early
settlement, we received $36 million in January 2009.
Marketing
and Midstream Revenues and Expenses
Marketing and midstream revenues and expenses are derived
primarily from our gas processing plants and gas pipeline
systems. 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 gas and NGLs, provisions of contractual agreements and the
amount of repair and maintenance activity required to maintain
anticipated processing levels and pipeline throughput volumes.
These factors increase the uncertainty inherent in estimating
future marketing and midstream revenues and expenses. Given
these uncertainties, we estimate that our 2009 marketing and
midstream operating profit will be between $375 million and
$425 million. We estimate that marketing and midstream
revenues will be
66
between $1.075 billion and $1.425 billion, and
marketing and midstream expenses will be between
$0.700 billion and $1.000 billion.
Production
and Operating Expenses
Our 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, gas and NGL prices
also have an effect on lease operating expenses and impact the
economic feasibility of planned workover projects.
Given these uncertainties, we expect that our 2009 lease
operating expenses will be between $1.93 billion and
$2.27 billion. Additionally, we estimate that our
production taxes for 2009 will be between 3.25% and 3.75% of
total oil, gas and NGL revenues, excluding the effect on
revenues from financial collar contracts upon which production
taxes are not assessed.
Depreciation,
Depletion and Amortization (DD&A)
Our 2009 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 2009 compared to the costs incurred for
such efforts and revisions to our year-end 2008 reserve
estimates that, based on prior experience, are likely to be made
during 2009. Our reserve estimates as of December 31, 2008
included negative price revisions of 473 MMBoe. The
following oil and gas property related DD&A estimates are
largely based on the assumption that the year-end 2008 negative
price revisions will not reverse during 2009. However, if such
negative price revisions reverse, in whole or in part, our
actual oil and gas property related DD&A rate could vary
materially from our estimate.
Given these uncertainties, we estimate that our oil and gas
property related DD&A rate will be between $10.25 per Boe
and $10.75 per Boe. Based on these DD&A rates and the
production estimates set forth earlier, oil and gas property
related DD&A expense for 2009 is expected to be between
$2.44 billion and $2.56 billion.
Additionally, we expect that our depreciation and amortization
expense related to non-oil and gas property fixed assets will
total between $315 million and $335 million in 2008.
Accretion
of Asset Retirement Obligations
Accretion of asset retirement obligations in 2009 is expected to
be between $85 million and $95 million.
General
and Administrative Expenses (G&A)
Our G&A includes employee compensation and benefits costs
and the costs of many different goods and services used in
support of our business. G&A varies with the level of our
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, we estimate our G&A for 2009 will
be between $565 million and $605 million. This
estimate includes approximately $110 million of non-cash,
share-based compensation, net of related capitalization in
accordance with the full cost method of accounting for oil and
gas properties.
Reduction
of Carrying Value of Oil and Gas Properties
Because of the volatile nature of oil and gas prices, it is not
possible to predict whether we will incur full cost writedowns
in 2009. However, such writedowns may be more likely to occur
during 2009 than in recent
67
periods, considering current and near-term estimates of oil and
gas prices, which are generally expected to be lower than prices
in existence prior to the fourth quarter of 2008.
We recognized full cost ceiling writedowns related to our oil
and gas properties in the United States, Canada and Brazil in
the fourth quarter of 2008. These writedowns resulted primarily
from significant declines in oil and gas prices compared to
previous quarter-end prices. The December 31, 2008 weighted
average wellhead prices for these countries are presented in the
following table.
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|
|
|
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|
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|
|
|
Country
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
United States
|
|
$
|
42.21
|
|
|
$
|
4.68
|
|
|
$
|
16.16
|
|
Canada
|
|
$
|
23.23
|
|
|
$
|
5.31
|
|
|
$
|
20.89
|
|
Brazil
|
|
$
|
26.61
|
|
|
|
N/A
|
|
|
|
N/A
|
|
N/A Not applicable.
The wellhead prices in the table above compare to the
December 31, 2008 NYMEX cash price of $44.60 per Bbl for
crude oil and the Henry Hub spot price of $5.71 per MMBtu for
gas. Should 2009 quarter-end prices approximate or decrease from
these December 31, 2008 prices, the likelihood that we will
incur full cost writedowns during 2009 will increase.
Interest
Expense
Future interest rates and debt outstanding have a significant
effect on our interest expense. We can only marginally influence
the prices we will receive in 2009 from sales of oil, gas and
NGLs and the resulting cash flow. This increases the margin of
error inherent in estimating future outstanding debt balances
and related interest expense. Other factors which affect
outstanding debt balances and related interest expense, such as
the amount and timing of capital expenditures are generally
within our control.
As of January 31, 2009, we had total debt of
$6.2 billion. This included $6.0 billion of fixed-rate
debt and $0.2 billion of variable-rate commercial paper
borrowings. The fixed-rate debt bears interest at an overall
weighted average rate of 7.23%. The commercial paper borrowings
bear interest at variable rates based on a standard index such
as the Federal Funds Rate, LIBOR, or the money market rate as
found on the commercial paper market. As of January 31,
2009, the weighted average variable rate for our commercial
paper borrowings was 3.33%. Additionally, any future borrowings
under our credit facilities would bear interest at various
fixed-rate options for periods up to twelve months and are
generally less than the prime rate.
Based on the factors above, we expect our 2009 interest expense
to be between $330 million and $340 million. This
estimate assumes no material changes in prevailing interest
rates or to our existing interest rate swap contracts presented
above. This estimate also assumes that our total debt will
increase approximately $1.0 billion during 2009, primarily
in the form of commercial paper borrowings.
The 2009 interest expense estimate above is comprised of three
primary components interest related to outstanding
debt, fees and issuance costs, and capitalized interest. We
expect the interest expense in 2009 related to our fixed-rate
and floating-rate debt, including net accretion of related
discounts, to be between $435 million and
$445 million. We expect the interest expense in 2009
related to facility and agency fees, amortization of debt
issuance costs and other miscellaneous items not related to
outstanding debt balances to be between $5 million and
$15 million. We also expect to capitalize between
$110 million and $120 million of interest during 2009.
68
Interest
Rate Risk Management
We also have interest rate swaps to mitigate a portion of the
fair value effects of interest rate fluctuations on our
fixed-rate debt. Under the terms of these swaps, we receive a
fixed rate and pay a variable rate on a total notional amount of
$1.05 billion. The key terms of these interest rate swaps
are presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Rate
|
|
|
Variable
|
|
|
|
Notional
|
|
|
Received
|
|
|
Rate Paid
|
|
Expiration
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
$
|
500
|
|
|
|
3.90
|
%
|
|
Federal funds rate
|
|
|
July 18, 2013
|
|
$
|
300
|
|
|
|
4.30
|
%
|
|
Six month LIBOR
|
|
|
July 18, 2011
|
|
$
|
250
|
|
|
|
3.85
|
%
|
|
Federal funds rate
|
|
|
July 22, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,050
|
|
|
|
4.00
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Including the effects of these swaps, the weighted-average
interest rate related to our fixed-rate debt was 6.64% as of
January 31, 2009.
Income
Taxes
Our financial income tax rate in 2009 will vary materially
depending on the actual amount of financial pre-tax earnings.
The tax rate for 2009 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 2009 income tax expense
regardless of the level of pre-tax earnings that are produced.
Given the uncertainty of pre-tax earnings, we expect that our
consolidated financial income tax rate in 2009 will be between
20% and 40%. The current income tax rate is expected to be
between 10% and 20%. The deferred income tax rate is expected to
be between 10% and 20%. 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 2009 financial
income tax rates.
Capital
Resources, Uses and Liquidity
Capital
Expenditures
Though we have completed several major property acquisitions in
recent years, these transactions are opportunity driven. Thus,
we do not budget, nor can we reasonably predict, the
timing or size of such possible acquisitions.
Our capital expenditures budget is based on an expected range of
future oil, gas and NGL prices as well as the expected costs of
the capital additions. Should actual prices received differ
materially from our price expectations for our future
production, some projects may be accelerated or deferred and,
consequently, may increase or decrease total 2009 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
our estimates.
Given the limitations discussed above, the following table shows
expected ranges for drilling, development and facilities
expenditures by geographic area. Development capital includes
development activity related to reserves classified as proved
and drilling that does not offset currently productive units and
for which there
69
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
|
|
|
United
|
|
|
|
|
|
|
|
|
|
|
|
|
States
|
|
|
States
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore
|
|
|
Offshore
|
|
|
Canada
|
|
|
International
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Development capital
|
|
$
|
1,520-$1,790
|
|
|
$
|
460-$540
|
|
|
$
|
740-$870
|
|
|
$
|
160-$200
|
|
|
$
|
2,880-$3,400
|
|
Exploration capital
|
|
$
|
150-$170
|
|
|
$
|
130-$150
|
|
|
$
|
40-$50
|
|
|
$
|
200-$230
|
|
|
$
|
520-$600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,670-$1,960
|
|
|
$
|
590-$690
|
|
|
$
|
780-$920
|
|
|
$
|
360-$430
|
|
|
$
|
3,400-$4,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In addition to the above expenditures for drilling, development
and facilities, we expect to spend between $325 million to
$425 million on our marketing and midstream assets, which
primarily include our oil pipelines, natural gas processing
plants, and gas pipeline systems. Additionally, we expect to
capitalize between $460 million and $480 million of
G&A expenses in accordance with the full cost method of
accounting and to capitalize between $110 million and
$120 million of interest. We also expect to pay between
$105 million and $115 million for plugging and
abandonment charges, and to spend between $230 million and
$250 million for other non-oil and gas property fixed
assets. We anticipate spending between $40 million and
$50 million to fulfill drilling commitments related to our
assets held for sale.
Other
Cash Uses
Our management expects the policy of paying a quarterly common
stock dividend to continue. With the current $0.16 per share
quarterly dividend rate and 444 million shares of common
stock outstanding as of December 31, 2008, dividends are
expected to approximate $284 million.
We have various defined benefit pension plans. The vast majority
of these plans are subject to minimum funding requirements.
During 2008, investment losses significantly reduced the funded
status of these plans. Accordingly, our 2009 contributions to
these plans are expected to be significantly higher than those
made in recent years. Depending on the funding targets we may
attempt to achieve, we estimate we will contribute between
$100 million and $175 million to our pension plans
during 2009.
Capital
Resources and Liquidity
Our estimated 2009 cash uses, including our drilling and
development activities and retirement of maturing debt, are
expected to be funded primarily through a combination of our
existing cash balances and operating cash flow. Any remaining
cash uses could be funded by increasing our borrowings under our
commercial paper program or with borrowings from the available
capacity under our credit facilities, which was approximately
$3.1 billion as of January 31, 2009. The amount of
operating cash flow to be generated during 2009 is uncertain due
to the factors affecting revenues and expenses as previously
cited. However, we expect our combined capital resources to be
adequate to fund our capital expenditures and other cash uses
for 2009.
If significant other acquisitions or other unplanned capital
requirements arise during the year, we could utilize our
existing credit facilities
and/or seek
to establish and utilize other sources of financing.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures about Market Risk
|
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about
our potential exposure to market risks. The term market
risk refers to the risk of loss arising from adverse
changes in oil, gas and NGL prices, interest rates and foreign
currency exchange rates. The following disclosures are not meant
to be precise indicators of expected future losses, but rather
indicators of reasonably possible losses. This forward-looking
information provides indicators of how we view and manage our
ongoing market risk exposures. All of our market risk sensitive
instruments were entered into for purposes other than
speculative trading.
70
Commodity
Price Risk
Our major market risk exposure is in the pricing applicable to
our oil, gas and NGL production. Realized pricing is primarily
driven by the prevailing worldwide price for crude oil and spot
market prices applicable to our U.S. and Canadian gas and
NGL production. Pricing for oil, gas and NGL production has been
volatile and unpredictable for several years. See
Item 1A. Risk Factors.
We periodically enter into financial hedging activities with
respect to a portion of our oil and gas production through
various financial transactions that hedge the future prices
received. These transactions include financial price swaps
whereby we will receive a fixed price for our production and pay
a variable market price to the contract counterparty, and
costless price collars that set a floor and ceiling price for
the hedged production. If the applicable monthly price indices
are outside of the ranges set by the floor and ceiling prices in
the various collars, we will settle the difference with the
counterparty to the collars. These financial hedging activities
are intended to support oil and gas prices at targeted levels
and to manage our exposure to oil and gas price fluctuations.
Based on gas contracts in place as of February 16, 2009 we
have approximately 0.3 Bcf per day of gas production in
2009 that is associated with price collars or fixed-price
contracts. This amount represents approximately 10% of our
estimated 2009 gas production, or 7% of our total Boe
production. All of the price collar contracts expire
December 31, 2009. Our fixed-price physical delivery
contracts extend through 2011. These physical delivery contracts
relate to our Canadian gas production and range from six Bcf to
14 Bcf per year. These physical delivery contracts are not
expected to have a material effect on our realized gas prices
from 2009 through 2011.
The key terms of our gas price collar contracts are presented in
the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor Price
|
|
|
Ceiling Price
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Floor
|
|
|
Average
|
|
|
Ceiling
|
|
|
Average
|
|
|
|
Volume
|
|
|
Range
|
|
|
Price
|
|
|
Range
|
|
|
Price
|
|
Period
|
|
(MMBtu/d)
|
|
|
($/MMBtu)
|
|
|
($/MMBtu)
|
|
|
($/MMBtu)
|
|
|
($/MMBtu)
|
|
|
First Quarter
|
|
|
277,056
|
|
|
$
|
8.00 - $8.50
|
|
|
$
|
8.25
|
|
|
$
|
10.60 - $14.00
|
|
|
$
|
12.02
|
|
Second Quarter
|
|
|
265,000
|
|
|
$
|
8.00 - $8.50
|
|
|
$
|
8.25
|
|
|
$
|
10.60 - $14.00
|
|
|
$
|
12.05
|
|
Third Quarter
|
|
|
265,000
|
|
|
$
|
8.00 - $8.50
|
|
|
$
|
8.25
|
|
|
$
|
10.60 - $14.00
|
|
|
$
|
12.05
|
|
Fourth Quarter
|
|
|
265,000
|
|
|
$
|
8.00 - $8.50
|
|
|
$
|
8.25
|
|
|
$
|
10.60 - $14.00
|
|
|
$
|
12.05
|
|
2009 Average
|
|
|
267,973
|
|
|
$
|
8.00 - $8.50
|
|
|
$
|
8.25
|
|
|
$
|
10.60 - $14.00
|
|
|
$
|
12.05
|
|
The fair values of our and gas price collars are largely
determined by estimates of the forward curves of relevant oil
and gas price indexes. At December 31, 2008, a 10% increase
in these forward curves would have decreased the net assets
recorded for our commodity hedging instruments by approximately
$54 million.
Interest
Rate Risk
At December 31, 2008, we had debt outstanding of
$5.8 billion. Of this amount, $4.8 billion, or 83%,
bears interest at fixed rates averaging 7.2%. Additionally, we
had $1.0 billion of outstanding commercial paper, bearing
interest at floating rates which averaged 3.0%.
We also have interest rate swaps to mitigate a portion of the
fair value effects of interest rate fluctuations on our
fixed-rate debt. Under the terms of these swaps, we receive a
fixed rate and pay a variable rate on a total notional amount of
$1.05 billion. The key terms of these interest rate swaps
are presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable
|
|
|
|
Notional
|
|
|
Fixed Rate Received
|
|
|
Rate Paid
|
|
Expiration
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
$
|
500
|
|
|
|
3.90
|
%
|
|
Federal funds rate
|
|
|
July 18, 2013
|
|
$
|
300
|
|
|
|
4.30
|
%
|
|
Six month LIBOR
|
|
|
July 18, 2011
|
|
$
|
250
|
|
|
|
3.85
|
%
|
|
Federal funds rate
|
|
|
July 22, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,050
|
|
|
|
4.00
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71
The fair values of our interest rate instruments are largely
determined by estimates of the forward curves of the Federal
Funds rate and LIBOR. At December 31, 2008, a 10% increase
in these forward curves would have decreased our net assets by
approximately $3 million.
Foreign
Currency Risk
Our net assets, net earnings and cash flows from our Canadian
subsidiaries are based on the U.S. dollar equivalent of
such amounts measured in the Canadian dollar functional
currency. Assets and liabilities of the Canadian subsidiaries
are translated to U.S. dollars using the applicable
exchange rate as of the end of a reporting period. Revenues,
expenses and cash flow are translated using the average exchange
rate during the reporting period. A 10% unfavorable change in
the Canadian-to-U.S. dollar exchange rate would not
materially impact our December 31, 2008 balance sheet.
72
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED
FINANCIAL STATEMENT SCHEDULES
|
|
|
|
|
|
|
|
74
|
|
Consolidated Financial Statements
|
|
|
76
|
|
|
|
|
76
|
|
|
|
|
77
|
|
|
|
|
78
|
|
|
|
|
79
|
|
|
|
|
80
|
|
|
|
|
81
|
|
All financial statement schedules are omitted as they are
inapplicable or the required information has been included in
the consolidated financial statements or notes thereto.
73
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Devon Energy Corporation:
We have audited the accompanying consolidated balance sheets of
Devon Energy Corporation and subsidiaries as of
December 31, 2008 and 2007, and the related consolidated
statements of operations, comprehensive (loss) income,
stockholders equity and cash flows for each of the years
in the three-year period ended December 31, 2008. We also
have audited Devon Energy Corporations internal control
over financial reporting as of December 31, 2008, based on
criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Devon Energy
Corporations management is responsible for these
consolidated financial statements, for maintaining effective
internal control over financial reporting, and for its
assessment of the effectiveness of internal control over
financial reporting, included in Managements Annual Report
contained in Item 9A. Controls and Procedures
of Devon Energy Corporations Annual Report on
Form 10-K.
Our responsibility is to express an opinion on these
consolidated financial statements and an opinion on the
Companys internal control over financial reporting based
on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are
free of material misstatement and whether effective internal
control over financial reporting was maintained in all material
respects. Our audits of the consolidated financial statements
included examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. Our audit of internal control over financial
reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a
material weakness exists, and testing and evaluating the design
and operating effectiveness of internal control based on the
assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We
believe that our audits provide a reasonable basis for our
opinions.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Devon Energy Corporation and subsidiaries as of
December 31, 2008 and 2007, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2008, in conformity
with U.S. generally accepted accounting principles. Also in
our opinion, Devon Energy Corporation maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2008, based on control
criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
74
As described in note 1 to the consolidated financial
statements, as of January 1, 2007, Devon Energy Corporation
adopted Statement of Financial Accounting Standards
No. 157, Fair Value Measurements, Statement of
Financial Accounting Standards No. 159, The Fair Value
Option for Financial Assets and Financial
Liabilities Including an Amendment of FASB Statement
No. 115, and Financial Accounting Standards Board
(FASB) Interpretation No. 48, Accounting for Uncertainty
in Income Taxes an interpretation of FASB Statement
No. 109. Additionally, during 2007, the Company adopted
the measurement date provisions of Statement of Financial
Accounting Standards No. 158, Employers Accounting
for Defined Benefit Pension and Other Postretirement
Plans an Amendment of FASB Statements No. 87,
88, 106, and 132(R).
KPMG LLP
Oklahoma City, Oklahoma
February 25, 2009
75
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions, except share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
379
|
|
|
$
|
1,364
|
|
Short-term investments, at fair value
|
|
|
|
|
|
|
372
|
|
Accounts receivable
|
|
|
1,412
|
|
|
|
1,779
|
|
Income taxes receivable
|
|
|
334
|
|
|
|
30
|
|
Derivative financial instruments, at fair value
|
|
|
282
|
|
|
|
12
|
|
Current assets held for sale
|
|
|
27
|
|
|
|
120
|
|
Other current assets
|
|
|
250
|
|
|
|
237
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
2,684
|
|
|
|
3,914
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, at cost, based on the full cost method
of accounting for oil and gas properties ($4,540 and $3,417
excluded from amortization in 2008 and 2007, respectively)
|
|
|
55,657
|
|
|
|
48,473
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
32,683
|
|
|
|
20,394
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,974
|
|
|
|
28,079
|
|
Investment in Chevron Corporation common stock, at fair value
|
|
|
|
|
|
|
1,324
|
|
Goodwill
|
|
|
5,579
|
|
|
|
6,172
|
|
Long-term assets held for sale
|
|
|
19
|
|
|
|
1,512
|
|
Other long-term assets, including $199 million at fair
value in 2008
|
|
|
652
|
|
|
|
455
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
31,908
|
|
|
$
|
41,456
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable trade
|
|
$
|
1,819
|
|
|
$
|
1,360
|
|
Revenues and royalties due to others
|
|
|
496
|
|
|
|
578
|
|
Income taxes payable
|
|
|
37
|
|
|
|
97
|
|
Short-term debt
|
|
|
180
|
|
|
|
1,004
|
|
Current portion of asset retirement obligations, at fair value
|
|
|
138
|
|
|
|
82
|
|
Current liabilities associated with assets held for sale
|
|
|
13
|
|
|
|
145
|
|
Accrued expenses and other current liabilities
|
|
|
452
|
|
|
|
391
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
3,135
|
|
|
|
3,657
|
|
|
|
|
|
|
|
|
|
|
Debentures exchangeable into shares of Chevron Corporation
common stock
|
|
|
|
|
|
|
641
|
|
Other long-term debt
|
|
|
5,661
|
|
|
|
6,283
|
|
Derivative financial instruments, at fair value
|
|
|
|
|
|
|
488
|
|
Asset retirement obligations, at fair value
|
|
|
1,347
|
|
|
|
1,236
|
|
Liabilities associated with assets held for sale
|
|
|
|
|
|
|
404
|
|
Other long-term liabilities
|
|
|
1,026
|
|
|
|
699
|
|
Deferred income taxes
|
|
|
3,679
|
|
|
|
6,042
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock of $1.00 par value. Authorized
4.5 million shares; issued 1.5 million shares
($150 million aggregate liquidation value) in 2007
|
|
|
|
|
|
|
1
|
|
Common stock of $0.10 par value. Authorized
1.0 billion shares; issued 443.7 million and
444.2 million shares in 2008 and 2007, respectively
|
|
|
44
|
|
|
|
44
|
|
Additional paid-in capital
|
|
|
6,257
|
|
|
|
6,743
|
|
Retained earnings
|
|
|
10,376
|
|
|
|
12,813
|
|
Accumulated other comprehensive income
|
|
|
383
|
|
|
|
2,405
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
17,060
|
|
|
|
22,006
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 10)
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
31,908
|
|
|
$
|
41,456
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
76
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions, except per share amounts)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
4,567
|
|
|
$
|
3,493
|
|
|
$
|
2,434
|
|
Gas sales
|
|
|
7,263
|
|
|
|
5,149
|
|
|
|
4,874
|
|
NGL sales
|
|
|
1,243
|
|
|
|
970
|
|
|
|
749
|
|
Net (loss) gain on oil and gas derivative financial instruments
|
|
|
(154
|
)
|
|
|
14
|
|
|
|
38
|
|
Marketing and midstream revenues
|
|
|
2,292
|
|
|
|
1,736
|
|
|
|
1,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
15,211
|
|
|
|
11,362
|
|
|
|
9,767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
2,217
|
|
|
|
1,828
|
|
|
|
1,425
|
|
Production taxes
|
|
|
522
|
|
|
|
340
|
|
|
|
341
|
|
Marketing and midstream operating costs and expenses
|
|
|
1,624
|
|
|
|
1,227
|
|
|
|
1,236
|
|
Depreciation, depletion and amortization of oil and gas
properties
|
|
|
3,253
|
|
|
|
2,655
|
|
|
|
2,058
|
|
Depreciation and amortization of non-oil and gas properties
|
|
|
256
|
|
|
|
203
|
|
|
|
173
|
|
Accretion of asset retirement obligations
|
|
|
86
|
|
|
|
74
|
|
|
|
47
|
|
General and administrative expenses
|
|
|
653
|
|
|
|
513
|
|
|
|
397
|
|
Interest expense
|
|
|
329
|
|
|
|
430
|
|
|
|
421
|
|
Change in fair value of other financial instruments
|
|
|
149
|
|
|
|
(34
|
)
|
|
|
178
|
|
Reduction of carrying value of oil and gas properties
|
|
|
10,379
|
|
|
|
|
|
|
|
36
|
|
Other income, net
|
|
|
(224
|
)
|
|
|
(98
|
)
|
|
|
(115
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net
|
|
|
19,244
|
|
|
|
7,138
|
|
|
|
6,197
|
|
(Loss) earnings from continuing operations before income taxes
|
|
|
(4,033
|
)
|
|
|
4,224
|
|
|
|
3,570
|
|
Income tax (benefit) expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
619
|
|
|
|
500
|
|
|
|
528
|
|
Deferred
|
|
|
(1,573
|
)
|
|
|
578
|
|
|
|
408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax (benefit) expense
|
|
|
(954
|
)
|
|
|
1,078
|
|
|
|
936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
|
(3,079
|
)
|
|
|
3,146
|
|
|
|
2,634
|
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income taxes
|
|
|
1,131
|
|
|
|
696
|
|
|
|
464
|
|
Income tax expense
|
|
|
200
|
|
|
|
236
|
|
|
|
252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations
|
|
|
931
|
|
|
|
460
|
|
|
|
212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
|
(2,148
|
)
|
|
|
3,606
|
|
|
|
2,846
|
|
Preferred stock dividends
|
|
|
5
|
|
|
|
10
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings applicable to common stockholders
|
|
$
|
(2,153
|
)
|
|
$
|
3,596
|
|
|
$
|
2,836
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
$
|
(6.95
|
)
|
|
$
|
7.05
|
|
|
$
|
5.94
|
|
Earnings from discontinued operations
|
|
|
2.10
|
|
|
|
1.03
|
|
|
|
0.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(4.85
|
)
|
|
$
|
8.08
|
|
|
$
|
6.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net (loss) earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
$
|
(6.95
|
)
|
|
$
|
6.97
|
|
|
$
|
5.87
|
|
Earnings from discontinued operations
|
|
|
2.10
|
|
|
|
1.03
|
|
|
|
0.47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(4.85
|
)
|
|
$
|
8.00
|
|
|
$
|
6.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
444
|
|
|
|
445
|
|
|
|
442
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
444
|
|
|
|
450
|
|
|
|
448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
77
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Net (loss) earnings
|
|
$
|
(2,148
|
)
|
|
$
|
3,606
|
|
|
$
|
2,846
|
|
Foreign currency translation:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cumulative translation adjustment
|
|
|
(1,960
|
)
|
|
|
1,389
|
|
|
|
(25
|
)
|
Income tax benefit (expense)
|
|
|
79
|
|
|
|
(42
|
)
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
(1,881
|
)
|
|
|
1,347
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss and prior service cost arising in current year
|
|
|
(254
|
)
|
|
|
(90
|
)
|
|
|
|
|
Recognition of net actuarial loss and prior service cost in net
earnings
|
|
|
16
|
|
|
|
14
|
|
|
|
|
|
Curtailment of pension benefits
|
|
|
|
|
|
|
16
|
|
|
|
|
|
Change in additional minimum pension liability
|
|
|
|
|
|
|
|
|
|
|
30
|
|
Income tax benefit (expense)
|
|
|
97
|
|
|
|
23
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
(141
|
)
|
|
|
(37
|
)
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in Chevron Corporation common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized holding gain
|
|
|
|
|
|
|
|
|
|
|
238
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
(86
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive (loss) income, net of tax
|
|
|
(2,022
|
)
|
|
|
1,309
|
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive (loss) income
|
|
$
|
(4,170
|
)
|
|
$
|
4,915
|
|
|
$
|
3,016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
78
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Other
|
|
|
|
|
|
Total
|
|
|
|
Preferred
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
Treasury
|
|
|
Stockholders
|
|
|
|
Stock
|
|
|
Shares
|
|
|
Value
|
|
|
Capital
|
|
|
Earnings
|
|
|
Income
|
|
|
Stock
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2005
|
|
$
|
1
|
|
|
|
443
|
|
|
$
|
44
|
|
|
$
|
6,928
|
|
|
$
|
6,477
|
|
|
$
|
1,414
|
|
|
$
|
(2
|
)
|
|
$
|
14,862
|
|
Net earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,846
|
|
|
|
|
|
|
|
|
|
|
|
2,846
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
170
|
|
|
|
|
|
|
|
170
|
|
Adoption of FASB Statement No. 158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(140
|
)
|
|
|
|
|
|
|
(140
|
)
|
Stock option exercises
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73
|
|
Restricted stock grants, net of cancellations
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
Common stock repurchased
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(277
|
)
|
|
|
(277
|
)
|
Common stock retired
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(278
|
)
|
|
|
|
|
|
|
|
|
|
|
278
|
|
|
|
|
|
Common stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(199
|
)
|
|
|
|
|
|
|
|
|
|
|
(199
|
)
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
(10
|
)
|
Share-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84
|
|
Share-based compensation tax benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2006
|
|
|
1
|
|
|
|
444
|
|
|
|
44
|
|
|
|
6,840
|
|
|
|
9,114
|
|
|
|
1,444
|
|
|
|
(1
|
)
|
|
|
17,422
|
|
Net earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,606
|
|
|
|
|
|
|
|
|
|
|
|
3,606
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,309
|
|
|
|
|
|
|
|
1,309
|
|
Adoption of FASB Statement No. 159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
364
|
|
|
|
(364
|
)
|
|
|
|
|
|
|
|
|
Adoption of FASB Interpretation No. 48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11
|
)
|
|
|
|
|
|
|
|
|
|
|
(11
|
)
|
Adoption of FASB Statement No. 158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
16
|
|
|
|
|
|
|
|
15
|
|
Stock option exercises
|
|
|
|
|
|
|
3
|
|
|
|
1
|
|
|
|
90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91
|
|
Restricted stock grants, net of cancellations
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock repurchased
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(362
|
)
|
|
|
(362
|
)
|
Common stock retired
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
(362
|
)
|
|
|
|
|
|
|
|
|
|
|
363
|
|
|
|
|
|
Common stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(249
|
)
|
|
|
|
|
|
|
|
|
|
|
(249
|
)
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
(10
|
)
|
Share-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
131
|
|
Share-based compensation tax benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007
|
|
|
1
|
|
|
|
444
|
|
|
|
44
|
|
|
|
6,743
|
|
|
|
12,813
|
|
|
|
2,405
|
|
|
|
|
|
|
|
22,006
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,148
|
)
|
|
|
|
|
|
|
|
|
|
|
(2,148
|
)
|
Other comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,022
|
)
|
|
|
|
|
|
|
(2,022
|
)
|
Stock option exercises
|
|
|
|
|
|
|
4
|
|
|
|
1
|
|
|
|
123
|
|
|
|
|
|
|
|
|
|
|
|
(8
|
)
|
|
|
116
|
|
Restricted stock grants, net of cancellations
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock repurchased
|
|
|
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(709
|
)
|
|
|
(709
|
)
|
Common stock retired
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
(716
|
)
|
|
|
|
|
|
|
|
|
|
|
717
|
|
|
|
|
|
Redemption of preferred stock
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
(149
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(150
|
)
|
Common stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(284
|
)
|
|
|
|
|
|
|
|
|
|
|
(284
|
)
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
Share-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
196
|
|
Share-based compensation tax benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008
|
|
$
|
|
|
|
|
444
|
|
|
$
|
44
|
|
|
$
|
6,257
|
|
|
$
|
10,376
|
|
|
$
|
383
|
|
|
$
|
|
|
|
$
|
17,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
79
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(2,148
|
)
|
|
$
|
3,606
|
|
|
$
|
2,846
|
|
Earnings from discontinued operations, net of tax
|
|
|
(931
|
)
|
|
|
(460
|
)
|
|
|
(212
|
)
|
Adjustments to reconcile (loss) earnings from continuing
operations to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
3,509
|
|
|
|
2,858
|
|
|
|
2,231
|
|
Deferred income tax (benefit) expense
|
|
|
(1,573
|
)
|
|
|
578
|
|
|
|
408
|
|
Net gain on sales of non-oil and gas property and equipment
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
(5
|
)
|
Reduction of carrying value of oil and gas properties
|
|
|
10,379
|
|
|
|
|
|
|
|
36
|
|
Other noncash charges
|
|
|
187
|
|
|
|
177
|
|
|
|
269
|
|
Net increase in working capital
|
|
|
(138
|
)
|
|
|
(499
|
)
|
|
|
(282
|
)
|
Increase in long-term other assets
|
|
|
(59
|
)
|
|
|
(92
|
)
|
|
|
(58
|
)
|
Increase (decrease) in long-term other liabilities
|
|
|
48
|
|
|
|
(5
|
)
|
|
|
141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities continuing
operations
|
|
|
9,273
|
|
|
|
6,162
|
|
|
|
5,374
|
|
Cash provided by operating activities discontinued
operations
|
|
|
135
|
|
|
|
489
|
|
|
|
619
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
9,408
|
|
|
|
6,651
|
|
|
|
5,993
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sales of property and equipment
|
|
|
117
|
|
|
|
76
|
|
|
|
40
|
|
Capital expenditures
|
|
|
(9,375
|
)
|
|
|
(6,158
|
)
|
|
|
(7,346
|
)
|
Proceeds from exchange of Chevron Corporation common stock
|
|
|
280
|
|
|
|
|
|
|
|
|
|
Purchases of short-term investments
|
|
|
(50
|
)
|
|
|
(934
|
)
|
|
|
(2,395
|
)
|
Sales of long-term and short-term investments
|
|
|
300
|
|
|
|
1,136
|
|
|
|
2,501
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities continuing
operations
|
|
|
(8,728
|
)
|
|
|
(5,880
|
)
|
|
|
(7,200
|
)
|
Cash provided by (used in) investing activities
discontinued operations
|
|
|
1,855
|
|
|
|
166
|
|
|
|
(249
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(6,873
|
)
|
|
|
(5,714
|
)
|
|
|
(7,449
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit facility repayments
|
|
|
(3,191
|
)
|
|
|
(757
|
)
|
|
|
|
|
Credit facility borrowings
|
|
|
1,741
|
|
|
|
2,207
|
|
|
|
|
|
Net commercial paper borrowings (repayments)
|
|
|
1
|
|
|
|
(804
|
)
|
|
|
1,808
|
|
Debt repayments
|
|
|
(1,031
|
)
|
|
|
(567
|
)
|
|
|
(862
|
)
|
Preferred stock redemption
|
|
|
(150
|
)
|
|
|
|
|
|
|
|
|
Proceeds from stock option exercises
|
|
|
116
|
|
|
|
91
|
|
|
|
73
|
|
Repurchases of common stock
|
|
|
(665
|
)
|
|
|
(326
|
)
|
|
|
(253
|
)
|
Dividends paid on common and preferred stock
|
|
|
(289
|
)
|
|
|
(259
|
)
|
|
|
(209
|
)
|
Excess tax benefits related to share-based compensation
|
|
|
60
|
|
|
|
44
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities
|
|
|
(3,408
|
)
|
|
|
(371
|
)
|
|
|
593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash
|
|
|
(116
|
)
|
|
|
51
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
|
(989
|
)
|
|
|
617
|
|
|
|
(850
|
)
|
Cash and cash equivalents at beginning of year (including cash
related to assets held for sale)
|
|
|
1,373
|
|
|
|
756
|
|
|
|
1,606
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year (including cash related
to assets held for sale)
|
|
$
|
384
|
|
|
$
|
1,373
|
|
|
$
|
756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
80
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
|
|
1.
|
Summary
of Significant Accounting Policies
|
Accounting policies used by Devon Energy Corporation and
subsidiaries (Devon) reflect industry practices and
conform to accounting principles generally accepted in the
United States of America. The more significant of such policies
are discussed below.
Nature
of Business and Principles of Consolidation
Devon is engaged primarily in oil and gas exploration,
development and production, and the acquisition of properties.
Such activities in the United States are concentrated in the
following geographic areas:
|
|
|
|
|
the Mid-Continent area of the central and southern United
States, principally in north and east Texas and Oklahoma;
|
|
|
|
the Permian Basin within Texas and New Mexico;
|
|
|
|
the Rocky Mountains area of the United States stretching from
the Canadian border into northern New Mexico;
|
|
|
|
the offshore areas of the Gulf of Mexico; and
|
|
|
|
the onshore areas of the Gulf Coast, principally in south Texas
and south Louisiana.
|
Devons Canadian operations are located primarily in the
provinces of Alberta, British Columbia and Saskatchewan.
Devons international operations outside of
North America are located primarily in Azerbaijan,
Brazil and China. In 2007, Devon sold its assets and terminated
its operations in Egypt. During 2008, Devon sold its assets and
terminated its operations in West Africa. These divestiture
activities are described more fully in Note 16.
Devon also has marketing and midstream operations that perform
various activities to support the oil and gas operations of
Devon as well as unrelated third parties. Such activities
include marketing gas, crude oil and NGLs, as well as
constructing and operating pipelines, storage and treating
facilities and natural gas processing plants.
The accounts of Devons controlled subsidiaries are
included in the accompanying consolidated financial statements.
All significant intercompany accounts and transactions have been
eliminated in consolidation.
Use of
Estimates in the Preparation of Financial
Statements
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements, and the reported amounts of revenues
and expenses during the reporting period. Actual amounts could
differ from these estimates, and changes in these estimates are
recorded when known. Significant items subject to such estimates
and assumptions include the following:
|
|
|
|
|
estimates of proved reserves and related estimates of the
present value of future net revenues;
|
|
|
|
the carrying value of oil and gas properties;
|
|
|
|
estimates of the fair value of reporting units and related
assessment of goodwill for impairment;
|
|
|
|
asset retirement obligations;
|
|
|
|
income taxes;
|
|
|
|
derivative financial instruments;
|
81
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
obligations related to employee benefits; and
|
|
|
|
legal and environmental risks and exposures.
|
Derivative
Financial Instruments
Devon is exposed to certain risks relating to its ongoing
business operations. Devons largest areas of risk exposure
relate to commodity prices, interest rates and Canadian to
U.S. dollar exchange rates. As discussed more fully below,
Devon uses derivative instruments primarily to manage commodity
price risk and interest rate risk. Besides these derivative
instruments, Devon also had an embedded option derivative
related to the fair value of its debentures exchangeable into
shares of Chevron common stock. Devon ceased to have this option
when the exchangeable debentures matured on August 15, 2008.
Devon periodically enters into derivative financial instruments
with respect to a portion of its oil and gas production that
hedge the future prices received. These instruments are used to
manage the inherent uncertainty of future revenues due to oil
and gas price volatility. Devons derivative financial
instruments include financial price swaps and costless price
collars. Under the terms of the swaps, Devon will receive a
fixed price for its production and pay a variable market price
to the contract counterparty. The price collars set a floor and
ceiling price for the hedged production. If the applicable
monthly price indices are outside of the ranges set by the floor
and ceiling prices in the various collars, Devon will
cash-settle the difference with the counterparty to the collars.
Devon periodically enters into interest rate swaps to manage its
exposure to interest rate volatility. Devon uses these swaps to
mitigate a portion of the fair value effects of interest rate
fluctuations on its fixed-rate debt. Under the terms of these
swaps, Devon receives a fixed rate and pays a variable rate on a
total notional amount.
All derivative financial instruments are recognized at their
current fair value as either assets or liabilities in the
balance sheet. Changes in the fair value of these derivative
financial instruments are recorded in the statement of
operations unless specific hedge accounting criteria are met. If
such criteria are met for cash flow hedges, the effective
portion of the change in the fair value is recorded directly to
accumulated other comprehensive income, a component of
stockholders equity, until the hedged transaction occurs.
The ineffective portion of the change in fair value is recorded
in the statement of operations. If such criteria are met for
fair value hedges, the change in the fair value is recorded in
the statement of operations with an offsetting amount recorded
for the change in fair value of the hedged item. Cash
settlements with counterparties to Devons derivative
financial instruments are also recorded in the statement of
operations.
A derivative financial instrument qualifies for hedge accounting
treatment if Devon designates the instrument as such on the date
the derivative contract is entered into or the date of a
business combination or other transaction that includes
derivative contracts. Additionally, Devon must document the
relationship between the hedging instrument and hedged item, as
well as the risk-management objective and strategy for
undertaking the instrument. Devon must also assess, both at the
instruments inception and on an ongoing basis, whether the
derivative is highly effective in offsetting the change in cash
flow of the hedged item. For derivative financial instruments
held during the three-year period ended December 31, 2008,
Devon chose not to meet the necessary criteria to qualify its
derivative financial instruments for hedge accounting treatment.
By using derivative financial instruments to hedge exposures to
changes in commodity prices and interest rates, Devon exposes
itself to credit risk and market risk. Credit risk is the
failure of the counterparty to perform under the terms of the
derivative contract. To mitigate this risk, the hedging
instruments are placed with a number of counterparties whom
Devon believes are minimal credit risks. It is Devons
policy to enter into derivative contracts only with investment
grade rated counterparties deemed by management to be competent
and competitive market makers.
82
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Market risk is the change in the value of a derivative financial
instrument that results from a change in commodity prices,
interest rates or other relevant underlyings. The market risks
associated with commodity price and interest rate contracts are
managed by establishing and monitoring parameters that limit the
types and degree of market risk that may be undertaken. The oil
and gas reference prices upon which the commodity instruments
are based reflect various market indices that have a high degree
of historical correlation with actual prices received by Devon.
Devon does not hold or issue derivative financial instruments
for speculative trading purposes.
See Note 3 for the amounts included in Devons
accompanying balance sheets and statements of operations
associated with its derivative financial instruments.
Discontinued
Operations
In November 2006 and January 2007, Devon announced plans to
divest its operations in Egypt and West Africa. As a result, all
amounts related to Devons operations in Egypt and West
Africa are classified as discontinued operations. The captions
assets held for sale and liabilities associated with assets held
for sale in the accompanying balance sheets present the assets
and liabilities associated with our discontinued operations. See
Note 16 for more discussion regarding these divestitures.
Property
and Equipment
Devon follows the full cost method of accounting for its oil and
gas properties. Accordingly, all costs incidental to the
acquisition, exploration and development of oil and gas
properties, including costs of undeveloped leasehold, dry holes
and leasehold equipment, are capitalized. Internal costs
incurred that are directly identified with acquisition,
exploration and development activities undertaken by Devon for
its own account, and that are not related to production, general
corporate overhead or similar activities, are also capitalized.
Interest costs incurred and attributable to unproved oil and gas
properties under current evaluation and major development
projects of oil and gas properties are also capitalized. All
costs related to production activities, including workover costs
incurred solely to maintain or increase levels of production
from an existing completion interval, are charged to expense as
incurred.
Under the full cost method of accounting, the net book value of
oil and gas properties, less related deferred income taxes, may
not exceed a calculated ceiling. The ceiling
limitation is the estimated after-tax future net revenues,
discounted at 10% per annum, from proved oil, gas and NGL
reserves plus the cost of properties not subject to
amortization. Estimated future net revenues exclude future cash
outflows associated with settling asset retirement obligations
included in the net book value of oil and gas properties. Such
limitations are imposed separately on a
country-by-country
basis and are tested quarterly. In calculating future net
revenues, 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,
including derivative contracts in place that qualify for hedge
accounting treatment. None of Devons derivative contracts
held during the three-year period ended December 31, 2008
qualified for hedge accounting treatment.
Any excess of the net book value, less related deferred taxes,
over the ceiling 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.
Capitalized costs are depleted by an equivalent
unit-of-production
method, converting gas to oil at the ratio of six thousand cubic
feet of gas to one barrel of oil. Depletion is calculated using
the capitalized costs, including estimated asset retirement
costs, plus the estimated future expenditures (based on current
costs) to be incurred in developing proved reserves, net of
estimated salvage values.
83
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Costs associated with unproved properties are excluded from the
depletion calculation until it is determined whether or not
proved reserves can be assigned to such properties. Devon
assesses its unproved properties for impairment quarterly.
Significant unproved properties are assessed individually. Costs
of insignificant unproved properties are transferred into the
depletion calculation over average holding periods ranging from
three years for onshore properties to seven years for offshore
properties.
No gain or loss is recognized upon disposal of oil and gas
properties unless such disposal significantly alters the
relationship between capitalized costs and proved reserves in a
particular country.
Depreciation of midstream pipelines are provided on a
unit-of-production
basis. Depreciation and amortization of other property and
equipment, including corporate and other midstream assets and
leasehold improvements, are provided using the straight-line
method based on estimated useful lives ranging from three to
39 years.
Devon recognizes liabilities for retirement obligations
associated with tangible long-lived assets, such as producing
well sites, offshore production platforms, and midstream
pipelines and processing plants when there is a legal obligation
associated with the retirement of such assets and the amount can
be reasonably estimated. The initial measurement of an asset
retirement obligation is recorded as a liability at its fair
value, with an offsetting asset retirement cost recorded as an
increase to the associated property and equipment on the
consolidated balance sheet. If the fair value of a recorded
asset retirement obligation changes, a revision is recorded to
both the asset retirement obligation and the asset retirement
cost. The asset retirement cost is depreciated using a
systematic and rational method similar to that used for the
associated property and equipment.
Investments
Devon reports its investments and other marketable securities at
fair value, except for debt securities in which management has
the ability and intent to hold until maturity. During the
three-year period ended December 31, 2008, Devons
investments consisted of auction rate securities and Chevron
Corporation (Chevron) common stock, which are
discussed below.
Auction
Rate Securities
At December 31, 2007, Devon held $372 million of
auction rate securities. Such securities are rated
AAA the highest rating by one or more
rating agencies and are collateralized by student loans that are
substantially guaranteed by the United States government.
Although Devons auction rate securities generally have
contractual maturities of more than 20 years, the
underlying interest rates on such securities are scheduled to
reset every seven to 28 days. Therefore, these auction rate
securities were generally priced and subsequently traded as
short-term investments because of the interest rate reset
feature. As a result, Devon classified its auction rate
securities as short-term investments in the accompanying
December 31, 2007 consolidated balance sheet and in prior
periods. At December 31, 2008, Devons auction rate
securities totaled $122 million.
Since February 8, 2008, Devon has experienced difficulty
selling its securities due to the failure of the auction
mechanism, which provided liquidity to these securities. An
auction failure means that the parties wishing to sell
securities could not do so. The securities for which auctions
have failed will continue to accrue interest and be auctioned
every seven to 28 days until the auction succeeds, the
issuer calls the securities or the securities mature.
From February 2008, when auctions began failing, to
December 31, 2008, issuers have redeemed $30 million
of Devons auction rate securities holdings at par.
However, based on continued auction failures and the current
market for Devons auction rate securities, Devon has
classified its securities as long-term investments as of
December 31, 2008. These securities are included in other
long-term assets in the
84
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
accompanying consolidated balance sheet. Devon has the ability
to hold the securities until maturity. At this time, Devon does
not believe the values of its long-term securities are impaired.
Chevron
Common Stock
Until October 31, 2008, Devon owned approximately
14.2 million shares of Chevron common stock. As described
in Note 6, Devon exchanged these shares on October 31,
2008 for cash and certain oil and gas property interests owned
by Chevron. These shares were held in connection with debt
previously owed by Devon that contained an exchange option.
The shares of Chevron common stock and the exchange option
embedded in the debt have always been recorded on Devons
balance sheet at fair value. However, pursuant to accounting
rules prior to January 1, 2007, only the change in fair
value of the embedded option had historically been included in
Devons results of operations. Conversely, the change in
fair value of the Chevron common stock had not been included in
Devons results of operations, but instead had been
recorded directly to stockholders equity as part of
accumulated other comprehensive income.
Effective January 1, 2007, Devon adopted Statement of
Financial Accounting Standards No. 159, The Fair Value
Option for Financial Assets and Financial
Liabilities Including an Amendment of FASB Statement
No. 115. Statement No. 159 allows a company the
option to value its financial assets and liabilities, on an
instrument by instrument basis, at fair value, and include the
change in fair value of such assets and liabilities in its
results of operations. Devon chose to apply the provisions of
Statement No. 159 to its shares of Chevron common stock.
Accordingly, beginning with the first quarter of 2007, the
change in fair value of the Chevron common stock owned by Devon,
along with the change in fair value of the related exchange
option, are both included in Devons results of operations.
For the year ended December 31, 2008, the change in fair
value of other financial instruments caption on Devons
statement of operations includes an unrealized loss of
$363 million related to the Chevron common stock and an
unrealized gain of $109 million related to the embedded
option. For the year ended December 31, 2007, the change in
fair value of other financial instruments caption on
Devons statement of operations includes an unrealized gain
of $281 million related to the Chevron common stock and an
unrealized loss of $248 million related to the embedded
option. For the year ended December 31, 2006, prior to
adopting Statement No. 159, an unrealized loss of
$181 million related to the change in fair value of the
embedded option were included in the change in fair value of
other financial instruments caption on Devons statement of
operations.
As of December 31, 2006, $364 million of after-tax
unrealized gains related to Devons investment in the
Chevron common stock was included in accumulated other
comprehensive income. This is the amount of unrealized gains
that, prior to Devons adoption of Statement No. 159,
had not been recorded in Devons historical results of
operations. Upon the adoption of Statement No. 159 as of
January 1, 2007, this $364 million net unrealized gain
was reclassified on Devons balance sheet from accumulated
other comprehensive income to retained earnings.
In conjunction with the adoption of Statement No. 159,
Devon also adopted on January 1, 2007 Statement of
Financial Accounting Standards No. 157, Fair Value
Measurements. Statement No. 157 provides a common
definition of fair value, establishes a framework for measuring
fair value and expands disclosures about fair value
measurements, but does not require any new fair value
measurements. The adoption of Statement No. 157 had no
impact on Devons financial statements, but the adoption
did result in additional required disclosures as set forth in
Note 11.
85
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Goodwill
Goodwill represents the excess of the purchase price of business
combinations over the fair value of the net assets acquired and
is tested for impairment at least annually. The impairment test
requires allocating goodwill and all other assets and
liabilities to assigned reporting units. The fair value of each
reporting unit is estimated and compared to the net book value
of the reporting unit. If the estimated fair value of the
reporting unit is less than the net book value, including
goodwill, then the goodwill is written down to the implied fair
value of the goodwill through a charge to expense. Because
quoted market prices are not available for Devons
reporting units, the fair values of the reporting units are
estimated based upon several valuation analyses, including
comparable companies, comparable transactions and premiums paid.
Devon performed annual impairment tests of goodwill in the
fourth quarters of 2008, 2007 and 2006. Based on these
assessments, no impairment of goodwill was required.
The table below provides a summary of Devons goodwill, by
assigned reporting unit, as of December 31, 2008 and 2007.
The decrease in goodwill from 2007 to 2008 is largely due to
changes in the exchange rate between the U.S. dollar and
the Canadian dollar.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
United States
|
|
$
|
3,046
|
|
|
$
|
3,049
|
|
Canada
|
|
|
2,465
|
|
|
|
3,055
|
|
International
|
|
|
68
|
|
|
|
68
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,579
|
|
|
$
|
6,172
|
|
|
|
|
|
|
|
|
|
|
Foreign
Currency Translation Adjustments
The U.S. dollar is the functional currency for Devons
consolidated operations except its Canadian subsidiaries, which
use the Canadian dollar as the functional currency. Therefore,
the assets and liabilities of Devons Canadian subsidiaries
are translated into U.S. dollars based on the current
exchange rate in effect at the balance sheet dates. Canadian
income and expenses are translated at average rates for the
periods presented. Translation adjustments have no effect on net
income and are included in accumulated other comprehensive
income in stockholders equity. The following table
presents the balances of Devons cumulative translation
adjustments included in accumulated other comprehensive income
(in millions).
|
|
|
|
|
December 31, 2005
|
|
$
|
1,216
|
|
December 31, 2006
|
|
$
|
1,219
|
|
December 31, 2007
|
|
$
|
2,566
|
|
December 31, 2008
|
|
$
|
685
|
|
Commitments
and Contingencies
Liabilities for loss contingencies arising from claims,
assessments, litigation or other sources are recorded when it is
probable that a liability has been incurred and the amount can
be reasonably estimated. Liabilities for environmental
remediation or restoration claims are recorded when it is
probable that obligations have been incurred and the amounts can
be reasonably estimated. Expenditures related to such
environmental matters are expensed or capitalized in accordance
with Devons accounting policy for property and equipment.
Reference is made to Note 10 for a discussion of amounts
recorded for these liabilities.
86
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Revenue
Recognition and Gas Balancing
Oil, gas and NGL revenues are recognized when production is sold
to a purchaser at a fixed or determinable price, delivery has
occurred, title has transferred and collectability of the
revenue is probable. Delivery occurs and title is transferred
when production has been delivered to a pipeline, railcar or
truck or a tanker lifting has occurred. Cash received relating
to future production is deferred and recognized when all revenue
recognition criteria are met. Taxes assessed by governmental
authorities on oil, gas and NGL revenues are presented
separately from such revenues as production taxes in the
statement of operations.
Devon follows the sales method of accounting for gas production
imbalances. The volumes of gas sold may differ from the volumes
to which Devon is entitled based on its interests in the
properties. These differences create imbalances that are
recognized as a liability only when the estimated remaining
reserves will not be sufficient to enable the underproduced
owner to recoup its entitled share through production. The
liability is priced based on current market prices. No
receivables are recorded for those wells where Devon has taken
less than its share of production unless all revenue recognition
criteria are met. If an imbalance exists at the time the
wells reserves are depleted, settlements are made among
the joint interest owners under a variety of arrangements.
Marketing and midstream revenues are recorded at the time
products are sold or services are provided to third parties at a
fixed or determinable price, delivery or performance has
occurred, title has transferred and collectibility of the
revenue is probable. Revenues and expenses attributable to gas
and NGL purchase, transportation and processing contracts are
reported on a gross basis when Devon takes title to the products
and has risks and rewards of ownership.
Major
Purchasers
During 2008, 2007 and 2006, no purchaser accounted for more than
10% of Devons revenues from continuing operations.
General
and Administrative Expenses
General and administrative expenses are reported net of amounts
reimbursed by working interest owners of the oil and gas
properties operated by Devon and net of amounts capitalized
pursuant to the full cost method of accounting.
Share
Based Compensation
Devon grants stock options, restricted stock awards and other
types of share-based awards to members of its Board of Directors
and selected employees. All such awards are measured at fair
value on the date of grant and are recognized as a component of
general and administrative expenses in the accompanying
statements of operations over the applicable vesting periods.
Income
Taxes
Devon is subject to current income taxes assessed by the federal
and various state jurisdictions in the United States and by
other foreign jurisdictions. In addition, Devon accounts for
deferred income taxes related to these jurisdictions using the
asset and liability method. Under this method, deferred tax
assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statement carrying amounts of assets and liabilities and their
respective tax bases. Deferred tax assets are also recognized
for the future tax benefits attributable to the expected
utilization of existing tax net operating loss carryforwards and
other types of carryforwards. Deferred tax assets and
liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary
differences and
87
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
carryforwards are expected to be recovered or settled. The
effect on deferred tax assets and liabilities of a change in tax
rates is recognized in income in the period that includes the
enactment date.
During 2008, Devon repatriated earnings from certain foreign
subsidiaries to the United States in conjunction with the
divestitures of its assets in West Africa. Subsequent to these
repatriations, Devon does not expect to repatriate similar
earnings from its historical operations in the foreseeable
future. As a result, undistributed earnings of foreign
subsidiaries included in continuing operations were determined
to be permanently reinvested as of December 31, 2008.
Therefore, no U.S. deferred income taxes were provided on
such amounts as of December 31, 2008. If it becomes
apparent that some or all of the undistributed earnings will be
distributed, Devon would then record taxes on those earnings.
In June 2006, the Financial Accounting Standards Board
(FASB) issued FASB Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109.
Interpretation No. 48 prescribes a threshold for
recognizing the financial statement effects of a tax position
when it is more likely than not, based on the technical merits,
that the position will be sustained upon examination by a taxing
authority. Recognized tax positions are initially and
subsequently measured as the largest amount of tax benefit that
is more likely than not of being realized upon ultimate
settlement with a taxing authority. Liabilities for unrecognized
tax benefits related to such tax positions are included in other
long-term liabilities unless the tax position is expected to be
settled within the upcoming year, in which case the liabilities
are included in accrued expenses and other current liabilities.
Interest and penalties related to unrecognized tax benefits are
included in income tax expense.
On January 1, 2007, Devon adopted Interpretation
No. 48 and recorded an $11 million reduction to the
January 1, 2007 balance of retained earnings related to
unrecognized tax benefits. The $11 million included
$8 million for related interest and penalties. An
additional $3 million of liabilities were recorded with a
corresponding increase to goodwill.
Additional information regarding Devons unrecognized tax
benefits, including changes in such amounts during 2008 and
2007, is provided in Note 15.
Net
(Loss) Earnings Per Common Share
Basic (loss) earnings per share is computed by dividing (loss)
earnings applicable to common stockholders by the weighted
average number of common shares outstanding for the period.
Diluted earnings per share is calculated using the treasury
stock method to reflect the potential dilution that could occur
if Devons dilutive outstanding stock options were
exercised.
Statements
of Cash Flows
For purposes of the consolidated statements of cash flows, Devon
considers all highly liquid investments with original
contractual maturities of three months or less to be cash
equivalents.
Recently
Issued Accounting Standards Not Yet Adopted
In December 2007, the FASB issued Statement of Financial
Accounting Standards No. 141(R), Business
Combinations, which replaces Statement No. 141.
Statement No. 141(R) retains the fundamental requirements
of Statement No. 141 that an acquirer be identified and the
acquisition method of accounting (previously called the purchase
method) be used for all business combinations. Statement
No. 141(R)s scope is broader than that of Statement
No. 141, which applied only to business combinations in
which control was obtained by transferring consideration. By
applying the acquisition method to all transactions and other
events in which one entity obtains control over one or more
other businesses, Statement No. 141(R) improves the
comparability of the information about business combinations
provided in financial reports. Statement No. 141(R)
establishes principles and requirements for how an acquirer
recognizes and measures identifiable assets
88
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
acquired, liabilities assumed and any noncontrolling interest in
the acquiree, as well as any resulting goodwill. Statement
No. 141(R) applies prospectively to business combinations
for which the acquisition date is on or after the beginning of
the first annual reporting period beginning on or after
December 15, 2008. Devon will evaluate how the new
requirements of Statement No. 141(R) would impact any
business combinations completed in 2009 or thereafter.
In December 2007, the FASB also issued Statement of Financial
Accounting Standards No. 160, Noncontrolling Interests
in Consolidated Financial Statements an amendment of
Accounting Research Bulletin No. 51. A
noncontrolling interest, sometimes called a minority interest,
is the portion of equity in a subsidiary not attributable,
directly or indirectly, to a parent. Statement No. 160
establishes accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. Under Statement No. 160,
noncontrolling interests in a subsidiary must be reported as a
component of consolidated equity separate from the parents
equity. Additionally, the amounts of consolidated net income
attributable to both the parent and the noncontrolling interest
must be reported separately on the face of the income statement.
Statement No. 160 is effective for fiscal years beginning
on or after December 15, 2008 and earlier adoption is
prohibited. The adoption of Statement No. 160 will not have
a material impact on Devons financial statements and
related disclosures.
In December 2008, the FASB issued Staff Position
No. FAS 132(R)-1, Employers Disclosures about
Postretirement Benefit Plan Assets. Staff Position 132(R)-1
amends FASB Statement No. 132 (revised 2003),
Employers Disclosures about Pensions and Other
Postretirement Benefits, to require additional disclosures
about the types of assets and associated risks in an
employers defined benefit pension or other postretirement
plan. Staff Position 132(R)-1 is effective for fiscal years
ending after December 15, 2009. Devon is evaluating the
impact the adoption of Staff Position 132(R)-1 will have on its
financial statement disclosures. However, Devons adoption
of Staff Position 132(R)-1 will not affect its current
accounting for its pension and postretirement plans.
Modernization
of Oil and Gas Reporting
In December 2008, the SEC adopted revisions to its required oil
and gas reporting disclosures. The revisions are intended to
provide investors with a more meaningful and comprehensive
understanding of oil and gas reserves. In the three decades that
have passed since adoption of these disclosure items, there have
been significant changes in the oil and gas industry. The
amendments are designed to modernize and update the oil and gas
disclosure requirements to align them with current practices and
changes in technology. In addition, the amendments concurrently
align the SECs full cost accounting rules with the revised
disclosures. The revised disclosure requirements must be
incorporated in registration statements filed on or after
January 1, 2010, and annual reports on
Form 10-K
for fiscal years ending on or after December 31, 2009. A
company may not apply the new rules to disclosures in quarterly
reports prior to the first annual report in which the revised
disclosures are required.
The following amendments have the greatest likelihood of
affecting Devons reserve disclosures, including the
comparability of its reserves disclosures with those of its peer
companies:
|
|
|
|
|
Pricing mechanism for oil and gas reserves estimation
The SECs current rules require proved
reserve estimates to be calculated using prices as of the end of
the period and held constant over the life of the reserves.
Price changes can be made only to the extent provided by
contractual arrangements. The revised rules require reserve
estimates to be calculated using a
12-month
average price. The
12-month
average price will also be used for purposes of calculating the
full cost ceiling limitations. Price changes can still be
incorporated to the extent defined by contractual arrangements.
The use of a
12-month
average price rather than a
single-day
price is expected to reduce the impact on reserve estimates and
the full cost ceiling limitations due to short-term volatility
and seasonality of prices.
|
89
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
Reasonable certainty The SECs current
definition of proved oil and gas reserves
incorporate certain specific concepts such as lowest known
hydrocarbons, which limits the ability to claim proved
reserves in the absence of information on fluid contacts in a
well penetration, notwithstanding the existence of other
engineering and geoscientific evidence. The revised rules amend
the definition to permit the use of new reliable technologies to
establish the reasonable certainty of proved reserves. This
revision also includes provisions for establishing levels of
lowest known hydrocarbons and highest known oil through reliable
technology other than well penetrations.
|
The revised rules also amend the definition of proved oil and
gas reserves to include reserves located beyond development
spacing areas that are immediately adjacent to developed spacing
areas if economic producibility can be established with
reasonable certainty. These revisions are designed to permit the
use of alternative technologies to establish proved reserves in
lieu of requiring companies to use specific tests. In addition,
they establish a uniform standard of reasonable certainty that
applies to all proved reserves, regardless of location or
distance from producing wells.
Because the revised rules generally expand the definition of
proved reserves, Devon expects its proved reserve estimates will
increase upon adoption of the revised rules. However, Devon is
not able to estimate the magnitude of the potential increase at
this time.
|
|
|
|
|
Unproved reserves The SECs current
rules prohibit disclosure of reserve estimates other than proved
in documents filed with the SEC. The revised rules permit
disclosure of probable and possible reserves and provide
definitions of probable reserves and possible reserves.
Disclosure of probable and possible reserves is optional.
However, such disclosures must meet specific requirements.
Disclosures of probable or possible reserves must provide the
same level of geographic detail as proved reserves and must
state whether the reserves are developed or undeveloped.
Probable and possible reserve disclosures must also provide the
relative uncertainty associated with these classifications of
reserves estimations. Devon has not yet determined whether it
will disclose its probable and possible reserves in documents
filed with the SEC.
|
The components of accounts receivable include the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Oil, gas and NGL revenues
|
|
$
|
789
|
|
|
$
|
1,140
|
|
Joint interest billings
|
|
|
263
|
|
|
|
240
|
|
Marketing and midstream revenues
|
|
|
153
|
|
|
|
183
|
|
Production tax credits
|
|
|
170
|
|
|
|
134
|
|
Other
|
|
|
42
|
|
|
|
87
|
|
|
|
|
|
|
|
|
|
|
Gross accounts receivable
|
|
|
1,417
|
|
|
|
1,784
|
|
Allowance for doubtful accounts
|
|
|
(5
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
Net accounts receivable
|
|
$
|
1,412
|
|
|
$
|
1,779
|
|
|
|
|
|
|
|
|
|
|
|
|
3.
|
Derivative
Financial Instruments
|
As discussed in Note 1, Devon periodically enters into
commodity and interest rate derivative financial instruments.
Also, during the first eight months of 2008 and all of 2007 and
2006, Devon held an embedded option derivative related to the
fair value of its debentures exchangeable into shares of Chevron
common stock.
90
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table presents the fair values of derivative
assets and liabilities included in the accompanying balance
sheets. None of Devons derivative instruments included in
the table have been designated as hedging instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset
|
|
|
Liability
|
|
|
|
Balance Sheet Caption
|
|
Derivatives
|
|
|
Derivatives
|
|
|
|
|
|
(In millions)
|
|
|
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
Gas price collars
|
|
Derivative financial instruments, current
|
|
$
|
255
|
|
|
$
|
|
|
Interest rate swaps
|
|
Derivative financial instruments, current
|
|
|
27
|
|
|
|
|
|
Interest rate swaps
|
|
Long-term other assets
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
359
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps
|
|
Derivative financial instruments, current
|
|
$
|
12
|
|
|
$
|
|
|
Embedded option
|
|
Derivative financial instruments,
long-term
|
|
|
|
|
|
|
488
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
12
|
|
|
$
|
488
|
|
|
|
|
|
|
|
|
|
|
The following table presents the cash settlements and unrealized
gains and losses on fair value changes included in the
accompanying statements of operations associated with these
derivative financial instruments. None of Devons
derivative instruments included in the table have been
designated as hedging instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Operations Caption
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(In millions)
|
|
|
Cash settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price collars
|
|
Net (loss) gain on oil and gas derivative financial instruments
|
|
$
|
27
|
|
|
$
|
|
|
|
$
|
|
|
Gas price collars
|
|
Net (loss) gain on oil and gas derivative financial instruments
|
|
|
(221
|
)
|
|
|
2
|
|
|
|
|
|
Gas price swaps
|
|
Net (loss) gain on oil and gas derivative financial instruments
|
|
|
(203
|
)
|
|
|
38
|
|
|
|
|
|
Interest rate swaps
|
|
Change in fair value of other financial instruments
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements
|
|
|
(396
|
)
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price collars
|
|
Net (loss) gain on oil and gas derivative financial instruments
|
|
|
255
|
|
|
|
(4
|
)
|
|
|
4
|
|
Gas price swaps
|
|
Net (loss) gain on oil and gas derivative financial instruments
|
|
|
(12
|
)
|
|
|
(22
|
)
|
|
|
34
|
|
Interest rate swaps
|
|
Change in fair value of other financial instruments
|
|
|
104
|
|
|
|
1
|
|
|
|
3
|
|
Embedded option
|
|
Change in fair value of other financial instruments
|
|
|
109
|
|
|
|
(248
|
)
|
|
|
(181
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses)
|
|
|
456
|
|
|
|
(273
|
)
|
|
|
(140
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) recognized on
statement of operations
|
|
$
|
60
|
|
|
$
|
(233
|
)
|
|
$
|
(140
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The components of other current assets include the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Inventories
|
|
$
|
195
|
|
|
$
|
145
|
|
Prepaid assets
|
|
|
49
|
|
|
|
46
|
|
Other
|
|
|
6
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
Other current assets
|
|
$
|
250
|
|
|
$
|
237
|
|
|
|
|
|
|
|
|
|
|
|
|
5.
|
Property
and Equipment and Asset Retirement Obligations
|
Property and equipment consists of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Oil and gas properties:
|
|
|
|
|
|
|
|
|
Subject to amortization
|
|
$
|
47,634
|
|
|
$
|
42,141
|
|
Not subject to amortization
|
|
|
4,540
|
|
|
|
3,417
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(31,574
|
)
|
|
|
(19,507
|
)
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
|
20,600
|
|
|
|
26,051
|
|
|
|
|
|
|
|
|
|
|
Other property and equipment
|
|
|
3,483
|
|
|
|
2,915
|
|
Accumulated depreciation and amortization
|
|
|
(1,109
|
)
|
|
|
(887
|
)
|
|
|
|
|
|
|
|
|
|
Net other property and equipment
|
|
|
2,374
|
|
|
|
2,028
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net of accumulated depreciation,
depletion and amortization
|
|
$
|
22,974
|
|
|
$
|
28,079
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of Devons oil and gas
properties not subject to amortization as of December 31,
2008. Evaluation of most of these properties, and therefore the
inclusion of their costs in amortized capital costs, is expected
to be completed within three to seven years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs Incurred In
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior to
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2006
|
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Acquisition costs
|
|
$
|
1,673
|
|
|
$
|
152
|
|
|
$
|
951
|
|
|
$
|
229
|
|
|
$
|
3,005
|
|
Exploration costs
|
|
|
654
|
|
|
|
243
|
|
|
|
125
|
|
|
|
129
|
|
|
|
1,151
|
|
Development costs
|
|
|
161
|
|
|
|
34
|
|
|
|
22
|
|
|
|
1
|
|
|
|
218
|
|
Capitalized interest
|
|
|
92
|
|
|
|
37
|
|
|
|
19
|
|
|
|
18
|
|
|
|
166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas properties not subject to amortization
|
|
$
|
2,580
|
|
|
$
|
466
|
|
|
$
|
1,117
|
|
|
$
|
377
|
|
|
$
|
4,540
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chief
Acquisition
On June 29, 2006, Devon acquired the oil and gas assets of
privately-owned Chief Holdings LLC (Chief). Devon
paid $2.0 billion in cash and assumed approximately
$0.2 billion of net liabilities in the
92
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
transaction for a total purchase price of $2.2 billion.
Devon funded the acquisition price, and the immediate retirement
of $180 million of assumed debt, with $718 million of
cash on hand and approximately $1.4 billion of borrowings
issued under its commercial paper program. The acquired oil and
gas properties consisted of 99.7 MMBoe (unaudited) of
proved reserves and leasehold totaling 169,000 net acres
located in the Barnett Shale area of north Texas. Devon
allocated approximately $1.0 billion of the purchase price
to proved reserves and approximately $1.2 billion to
unproved properties.
Asset
Retirement Obligations
Following is a reconciliation of the asset retirement
obligations for the years ended December 31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Asset retirement obligations as of beginning of year
|
|
$
|
1,318
|
|
|
$
|
857
|
|
Liabilities incurred
|
|
|
59
|
|
|
|
57
|
|
Liabilities settled
|
|
|
(86
|
)
|
|
|
(68
|
)
|
Liabilities assumed by others
|
|
|
|
|
|
|
(3
|
)
|
Revision of estimated obligation
|
|
|
244
|
|
|
|
311
|
|
Accretion expense on discounted obligation
|
|
|
86
|
|
|
|
74
|
|
Foreign currency translation adjustment
|
|
|
(136
|
)
|
|
|
90
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations as of end of year
|
|
|
1,485
|
|
|
|
1,318
|
|
Less current portion
|
|
|
138
|
|
|
|
82
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, long-term
|
|
$
|
1,347
|
|
|
$
|
1,236
|
|
|
|
|
|
|
|
|
|
|
During 2008 and 2007, Devon recognized revisions to its asset
retirement obligations totaling $244 million and
$311 million, respectively. The primary factors causing the
2008 fair value increase were an overall increase in abandonment
cost estimates and a decrease in the discount rate used to
present value the obligations. In addition, higher abandonment
cost estimates related to certain offshore platforms that were
destroyed by Hurricane Ike resulted in an $82 million
increase in 2008. See additional discussion regarding this
revision in Note 10 Hurricane Contingencies.
The primary factors causing the 2007 fair value increase were an
overall increase in abandonment cost estimates and an increase
in the assumed inflation rate. The effect of these factors was
partially offset by the effect of an increase in the discount
rate used to calculate the present value of the obligations.
|
|
6.
|
Investment
in Chevron Corporation Common Stock
|
Until October 31, 2008, Devon owned 14.2 million
shares of Chevron common stock. These shares were held in
connection with debt owed by Devon that contained an exchange
option. The exchange option allowed the debt holders, prior to
the debts maturity of August 15, 2008, to exchange
the debt for shares of Chevron common stock owned by Devon.
However, Devon had the option to settle any exchanges with cash
equal to the market value of Chevron common stock at the time of
the exchange. Devon settled exchange requests during 2008 and
2007 by paying $1.0 billion during 2008 and
$0.2 billion during 2007.
On October 31, 2008, Devon transferred its
14.2 million shares of Chevron common stock to Chevron. In
exchange, Devon received Chevrons interest in the
Drunkards Wash coalbed natural gas field in east-central
Utah and $280 million in cash. The field has approximately
51,000 net acres and had net production of about
40 million cubic feet of natural gas equivalent per day
(unaudited) at the time of the exchange.
93
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
7.
|
Debt and
Related Expenses
|
A summary of Devons debt is as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Senior Credit Facility borrowings
|
|
$
|
|
|
|
$
|
1,450
|
|
Commercial paper
|
|
|
1,005
|
|
|
|
1,004
|
|
Debentures exchangeable into shares of Chevron common stock:
|
|
|
|
|
|
|
|
|
4.90% retired on August 15, 2008
|
|
|
|
|
|
|
381
|
|
4.95% retired on August 15, 2008
|
|
|
|
|
|
|
271
|
|
Discount on exchangeable debentures
|
|
|
|
|
|
|
(11
|
)
|
Other debentures and notes:
|
|
|
|
|
|
|
|
|
10.125% due November 15, 2009
|
|
|
177
|
|
|
|
177
|
|
6.875% due September 30, 2011
|
|
|
1,750
|
|
|
|
1,750
|
|
7.25% due October 1, 2011
|
|
|
350
|
|
|
|
350
|
|
8.25% due July 1, 2018
|
|
|
125
|
|
|
|
125
|
|
7.50% due September 15, 2027
|
|
|
150
|
|
|
|
150
|
|
7.875% due September 30, 2031
|
|
|
1,250
|
|
|
|
1,250
|
|
7.95% due April 15, 2032
|
|
|
1,000
|
|
|
|
1,000
|
|
Other
|
|
|
10
|
|
|
|
|
|
Net premium on other debentures and notes
|
|
|
24
|
|
|
|
31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,841
|
|
|
|
7,928
|
|
Less amount classified as short-term debt
|
|
|
180
|
|
|
|
1,004
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
5,661
|
|
|
$
|
6,924
|
|
|
|
|
|
|
|
|
|
|
Debt maturities as of December 31, 2008, excluding premiums
and discounts, are as follows (in millions):
|
|
|
|
|
2009
|
|
$
|
177
|
|
2010
|
|
|
|
|
2011
|
|
|
2,100
|
|
2012
|
|
|
10
|
|
2013
|
|
|
|
|
2014 and thereafter
|
|
|
3,530
|
|
|
|
|
|
|
Total
|
|
$
|
5,817
|
|
|
|
|
|
|
Credit
Lines
Devon has two revolving lines of credit that can be accessed to
provide liquidity as needed. As of December 31, 2008,
Devons combined available capacity under these credit
facilities, net of $119 million of outstanding letters of
credit and $1.0 billion of outstanding commercial paper,
was $2.2 billion.
Devon has a $2.65 billion syndicated, unsecured revolving
line of credit (the Senior Credit Facility). The
maturity date for $2.15 billion of the Senior Credit
Facility is April 7, 2013. The maturity date for the
remaining $0.5 billion is April 7, 2012. All amounts
outstanding will be due and payable on the respective maturity
dates unless the maturity is extended. Prior to each April 7
anniversary date, Devon has the option to
94
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
extend the maturity of the Senior Credit Facility for one year,
subject to the approval of the lenders. The Senior Credit
Facility includes a revolving Canadian subfacility in a maximum
amount of U.S. $500 million.
Amounts borrowed under the Senior Credit Facility may, at the
election of Devon, bear interest at various fixed rate options
for periods of up to twelve months. Such rates are generally
less than the prime rate. However, Devon may elect to borrow at
the prime rate. The Senior Credit Facility currently provides
for an annual facility fee of $1.9 million that is payable
quarterly in arrears. As of December 31, 2008, there were
no borrowings under the Senior Credit Facility.
On November 5, 2008, Devon established a new
$700 million
364-day,
syndicated, unsecured revolving senior credit facility (the
Short-Term Facility). The Short-Term Facility
provides Devon with incremental liquidity for near-term capital
expenditures.
The Short-Term Facility matures on November 3, 2009. On the
maturity date, all amounts outstanding will be due and payable
at that time. Amounts borrowed under the Short-Term Facility
bear interest at various fixed rate options for periods of up to
12 months. Such rates are generally based on LIBOR or the
prime rate. The Short-Term Facility currently provides for an
annual facility fee of approximately $0.7 million that is
payable quarterly in arrears. As of December 31, 2008,
there were no borrowings under the Short-Term Facility.
The Senior Credit Facility and Short-Term Facility contain only
one material financial covenant. This covenant requires
Devons ratio of total funded debt to total capitalization
to be less than 65%. The credit agreement contains definitions
of total funded debt and total capitalization that include
adjustments to the respective amounts reported in the
consolidated financial statements. Also, total capitalization is
adjusted to add back noncash financial writedowns such as full
cost ceiling impairments or goodwill impairments. As of
December 31, 2008, Devon was in compliance with this
covenant. Devons
debt-to-capitalization
ratio at December 31, 2008, as calculated pursuant to the
terms of the agreement, was 18.6%.
Commercial
Paper
Devon also has access to short-term credit under its commercial
paper program. Total borrowings under the commercial paper
program may not exceed $2.85 billion. Also, any borrowings
under the commercial paper program reduce available capacity
under the Senior Credit Facility or the Short-Term Facility on a
dollar-for-dollar
basis. Commercial paper debt generally has a maturity of between
one and 90 days, although it can have a maturity of up to
365 days, and bears interest at rates agreed to at the time
of the borrowing. The interest rate is based on a standard index
such as the Federal Funds Rate, LIBOR, or the money market rate
as found on the commercial paper market. As of December 31,
2008, Devon had $1.0 billion of commercial paper debt
outstanding at an average rate of 3.00%. The average borrowing
rate for Devons $1.0 billion of commercial paper debt
outstanding at December 31, 2007 was 5.07%.
In January 2009, Devon issued $500 million of
5.625% senior notes due January 15, 2014 and
$700 million of 6.30% senior notes due
January 15, 2019. The net proceeds from issuance of this
debt were used primarily to repay Devons outstanding
commercial paper as of December 31, 2008. Therefore, the
$1.0 billion of outstanding commercial paper is classified
as long-term debt in the accompanying 2008 consolidated balance
sheet. Outstanding commercial paper is classified as short-term
debt in the accompanying 2007 consolidated balance sheet.
Other
Debentures and Notes
Following are descriptions of the various other debentures and
notes outstanding at December 31, 2008, as listed in the
table presented at the beginning of this note.
95
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Ocean
Debt
As a result of the merger with Ocean Energy, Inc., which closed
April 25, 2003, Devon assumed $1.8 billion of debt.
The table below summarizes the debt assumed that remains
outstanding, the fair value of the debt at April 25, 2003,
and the effective interest rate of the debt assumed after
determining the fair values of the respective notes using
April 25, 2003, market interest rates. The premiums
resulting from fair values exceeding face values are being
amortized using the effective interest method. All of the notes
are general unsecured obligations of Devon.
|
|
|
|
|
|
|
|
|
|
|
Fair Value of
|
|
|
Effective Rate of
|
|
Debt Assumed
|
|
Debt Assumed
|
|
|
Debt Assumed
|
|
|
|
(In millions)
|
|
|
|
|
|
7.250% due October 2011 (principal of $350 million)
|
|
$
|
406
|
|
|
|
4.9
|
%
|
8.250% due July 2018 (principal of $125 million)
|
|
$
|
147
|
|
|
|
5.5
|
%
|
7.500% due September 2027 (principal of $150 million)
|
|
$
|
169
|
|
|
|
6.5
|
%
|
10.125% Debentures
due November 15, 2009
These debentures were assumed as part of the PennzEnergy
acquisition. The fair value of the debentures was determined
using August 17, 1999, market interest rates. As a result,
a premium was recorded on these debentures, which lowered the
effective interest rate to 8.9%. The premium is being amortized
using the effective interest method.
6.875% Notes
due September 30, 2011 and 7.875% Debentures due
September 30, 2031
On October 3, 2001, Devon, through Devon Financing
Corporation, U.L.C. (Devon Financing), a
wholly-owned finance subsidiary, sold these notes and
debentures, which are unsecured and unsubordinated obligations
of Devon Financing. Devon has fully and unconditionally
guaranteed on an unsecured and unsubordinated basis the
obligations of Devon Financing under the debt securities. The
proceeds from the issuance of these debt securities were used to
fund a portion of the acquisition of Anderson Exploration.
7.95% Notes
due April 15, 2032
On March 25, 2002, Devon sold these notes, which are
unsecured and unsubordinated obligations of Devon. The net
proceeds received, after discounts and issuance costs, were
$986 million and were used to retire other indebtedness.
Interest
Expense
The following schedule includes the components of interest
expense between 2006 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Interest based on debt outstanding
|
|
$
|
426
|
|
|
$
|
508
|
|
|
$
|
486
|
|
Capitalized interest
|
|
|
(111
|
)
|
|
|
(102
|
)
|
|
|
(79
|
)
|
Other interest
|
|
|
14
|
|
|
|
24
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense
|
|
$
|
329
|
|
|
$
|
430
|
|
|
$
|
421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Devon has various non-contributory defined benefit pension
plans, including qualified plans (Qualified Plans)
and nonqualified plans (Supplemental Plans). The
Qualified Plans provide retirement benefits for
96
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
U.S. and Canadian employees meeting certain age and service
requirements. Benefits for the Qualified Plans are based on the
employees years of service and compensation and are funded
from assets held in the plans trusts.
Devons funding policy regarding the Qualified Plans is to
contribute the amount of funds necessary for the Qualified
Plans assets to approximately equal the present value of
benefits earned by the participants, as calculated in accordance
with the provisions of the Pension Protection Act. As of
December 31, 2008 and 2007, the fair values of the
Qualified Plans assets were $430 million and
$619 million, respectively. The assets were
$209 million less and $62 million more, respectively,
than the related accumulated benefit obligation. The amount of
contributions required during future periods will depend on
investment returns from the plan assets during the same period
as well as changes in long-term interest rates.
The Supplemental Plans provide retirement benefits for certain
employees whose benefits under the Qualified Plans are limited
by income tax regulations. The Supplemental Plans benefits
are based on the employees years of service and
compensation. For certain Supplemental Plans, Devon has
established trusts to fund these plans benefit
obligations. The total value of these trusts was
$50 million and $59 million at December 31, 2008
and 2007, respectively, and is included in noncurrent other
assets in the consolidated balance sheets. For the remaining
Supplemental Plans for which trusts have not been established,
benefits are funded from Devons available cash and cash
equivalents.
Devon also has defined benefit postretirement plans
(Postretirement Plans) that provide benefits for
substantially all U.S. employees. The Postretirement Plans
provide medical and, in some cases, life insurance benefits and
are, depending on the type of plan, either contributory or
non-contributory. Benefit obligations for the Postretirement
Plans are estimated based on Devons future cost-sharing
intentions. Devons funding policy for the Postretirement
Plans is to fund the benefits as they become payable with
available cash and cash equivalents.
Revisions
to Retirement Plans
In the second quarter of 2007, Devon adopted an enhanced defined
contribution structure related to its 401(k) Incentive Savings
Plan (401(k) Plan) to be effective January 1,
2008. Participants in this enhanced defined contribution
structure continue to receive a discretionary match of a
percentage of their contributions to the 401(k) Plan. These
participants also receive additional, nondiscretionary
contributions by Devon calculated as a percentage of annual
compensation. The percentage varies based on the employees
years of service.
On or before November 15, 2007, existing eligible employees
elected to either continue to participate in the defined benefit
plan or participate in the enhanced defined contribution
structure of the 401(k) Plan. Employees who elected to continue
participating in the defined benefit plans continue to accrue
benefits under the existing provisions of such plans. Employees
who elected to participate in the enhanced defined contribution
structure receive enhanced contributions to the 401(k) Plan and
retain the benefits that they had accrued under the defined
benefit plan as of December 31, 2007. However, such
employees are only entitled to the benefits that have accrued in
the defined benefit plans as of December 31, 2007, after
all applicable vesting requirements have been met. Employees
hired on or after October 1, 2007 do not have an election
and only participate in the 401(k) Plan and the enhanced defined
contribution structure.
For those employees who elected to participate in the enhanced
defined contribution structure, Devons pension benefit
obligation included $16 million related to projected future
years of service for these employees. Because this portion of
the employees benefits was curtailed upon their election,
Devon reduced its pension liabilities by $16 million in the
fourth quarter of 2007.
97
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Change
in Measurement Date
In September 2006, the FASB issued Statement of Financial
Accounting Standards No. 158, Employers Accounting
for Defined Benefit Pension and Other Postretirement
Plans an amendment of FASB Statements No. 87,
88, 106, and 132(R). Statement No. 158 requires the
measurement of plan assets and benefit obligations as of the
date of the employers fiscal year-end, beginning with
fiscal years ending after December 15, 2008. Although not
required until 2008, Devon adopted this measurement-date
requirement in the second quarter of 2007 and changed its
measurement date from November 30 to December 31. As a
result, Devon used data as of December 31, 2006 to
remeasure its plans assets and benefit obligations previously
measured using data as of November 30, 2006. As a result of
the remeasurement, Devon recognized the following amounts in the
second quarter of 2007.
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
(In millions)
|
|
|
Other long-term liabilities
|
|
$
|
(27
|
)
|
Deferred income tax liabilities
|
|
$
|
9
|
|
Retained earnings
|
|
$
|
(1
|
)
|
Accumulated other comprehensive income
|
|
$
|
16
|
|
General and administrative expenses
|
|
$
|
(3
|
)
|
98
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Benefit
Obligations and Plan Assets
The following table presents the status of Devons pension
and other postretirement benefit plans for 2008 and 2007. The
benefit obligation for pension plans represents the projected
benefit obligation, while the benefit obligation for the
postretirement benefit plans represents the accumulated benefit
obligation. The accumulated benefit obligation differs from the
projected benefit obligation in that the former includes no
assumption about future compensation levels. The accumulated
benefit obligation for pension plans at December 31, 2008
and 2007 was $795 million and $693 million,
respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$
|
849
|
|
|
$
|
768
|
|
|
$
|
71
|
|
|
$
|
52
|
|
Effect of change in measurement date
|
|
|
|
|
|
|
(23
|
)
|
|
|
|
|
|
|
(1
|
)
|
Service cost
|
|
|
41
|
|
|
|
30
|
|
|
|
1
|
|
|
|
1
|
|
Interest cost
|
|
|
54
|
|
|
|
46
|
|
|
|
4
|
|
|
|
3
|
|
Participant contributions
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
2
|
|
Plan amendments
|
|
|
9
|
|
|
|
17
|
|
|
|
|
|
|
|
23
|
|
Curtailment gain
|
|
|
|
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
Foreign exchange rate changes
|
|
|
(6
|
)
|
|
|
6
|
|
|
|
|
|
|
|
|
|
Actuarial loss (gain)
|
|
|
17
|
|
|
|
51
|
|
|
|
(15
|
)
|
|
|
(2
|
)
|
Benefits paid
|
|
|
(33
|
)
|
|
|
(30
|
)
|
|
|
(7
|
)
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
|
931
|
|
|
|
849
|
|
|
|
56
|
|
|
|
71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
|
619
|
|
|
|
590
|
|
|
|
|
|
|
|
|
|
Effect of change in measurement date
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
Actual return on plan assets
|
|
|
(178
|
)
|
|
|
47
|
|
|
|
|
|
|
|
|
|
Employer contributions
|
|
|
25
|
|
|
|
6
|
|
|
|
5
|
|
|
|
5
|
|
Participant contributions
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
2
|
|
Benefits paid
|
|
|
(33
|
)
|
|
|
(30
|
)
|
|
|
(7
|
)
|
|
|
(7
|
)
|
Foreign exchange rate changes
|
|
|
(3
|
)
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year
|
|
|
430
|
|
|
|
619
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status at end of year
|
|
$
|
(501
|
)
|
|
$
|
(230
|
)
|
|
$
|
(56
|
)
|
|
$
|
(71
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts recognized in balance sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent assets
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
|
|
|
$
|
|
|
Current liabilities
|
|
|
(10
|
)
|
|
|
(8
|
)
|
|
|
(5
|
)
|
|
|
(6
|
)
|
Noncurrent liabilities
|
|
|
(493
|
)
|
|
|
(225
|
)
|
|
|
(51
|
)
|
|
|
(65
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net amount
|
|
$
|
(501
|
)
|
|
$
|
(230
|
)
|
|
$
|
(56
|
)
|
|
$
|
(71
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts recognized in accumulated other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss (gain)
|
|
$
|
440
|
|
|
$
|
208
|
|
|
$
|
(13
|
)
|
|
$
|
2
|
|
Prior service cost (benefit)
|
|
|
28
|
|
|
|
22
|
|
|
|
13
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
468
|
|
|
$
|
230
|
|
|
$
|
|
|
|
$
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
99
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The plan assets for pension benefits in the table above exclude
the assets held in trusts for the Supplemental Plans. However,
employer contributions for pension benefits in the table above
include $9 and $6 million for 2008 and 2007, respectively,
which were transferred from the trusts established for the
Supplemental Plans.
Certain of Devons pension plans have a projected benefit
obligation in excess of plan assets at December 31, 2008
and 2007. The aggregate benefit obligation and fair value of
plan assets for these plans is included below.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Projected benefit obligation
|
|
$
|
921
|
|
|
$
|
834
|
|
Fair value of plan assets
|
|
$
|
417
|
|
|
$
|
601
|
|
Certain of Devons pension plans have an accumulated
benefit obligation in excess of plan assets at December 31,
2008 and 2007. The aggregate accumulated benefit obligation and
fair value of plan assets for these plans is included below.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Accumulated benefit obligation
|
|
$
|
784
|
|
|
$
|
135
|
|
Fair value of plan assets
|
|
$
|
417
|
|
|
$
|
|
|
100
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The plan assets included in the above two tables exclude the
Supplemental Plan trusts, which had a total value of
$50 million and $59 million at December 31, 2008
and 2007, respectively.
Net
Periodic Benefit Cost and Other Comprehensive
Income
The following table presents the components of net periodic
benefit cost and other comprehensive income for Devons
pension and other postretirement benefit plans for 2008, 2007
and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
Pension Benefits
|
|
|
Postretirement Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
41
|
|
|
$
|
30
|
|
|
$
|
23
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
Interest cost
|
|
|
54
|
|
|
|
46
|
|
|
|
39
|
|
|
|
4
|
|
|
|
3
|
|
|
|
3
|
|
Expected return on plan assets
|
|
|
(50
|
)
|
|
|
(49
|
)
|
|
|
(44
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Curtailment and settlement expense
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plan amendment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
Recognition net actuarial loss
|
|
|
14
|
|
|
|
12
|
|
|
|
12
|
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
Recognition of prior service cost
|
|
|
2
|
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net periodic benefit cost
|
|
|
61
|
|
|
|
41
|
|
|
|
31
|
|
|
|
7
|
|
|
|
6
|
|
|
|
5
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial loss (gain) arising in current year
|
|
|
245
|
|
|
|
54
|
|
|
|
|
|
|
|
(15
|
)
|
|
|
(3
|
)
|
|
|
|
|
Prior service cost arising in current year
|
|
|
9
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
22
|
|
|
|
|
|
Recognition of net actuarial loss in net periodic benefit cost
|
|
|
(14
|
)
|
|
|
(12
|
)
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
Recognition of prior service cost in net periodic benefit cost
|
|
|
(2
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
Curtailment of pension benefits
|
|
|
|
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in additional minimum pension liability
|
|
|
|
|
|
|
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income (loss)
|
|
|
238
|
|
|
|
42
|
|
|
|
30
|
|
|
|
(17
|
)
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized
|
|
$
|
299
|
|
|
$
|
83
|
|
|
$
|
61
|
|
|
$
|
10
|
|
|
$
|
24
|
|
|
$
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents the estimated net actuarial loss
and prior service cost for the pension and other postretirement
plans that will be amortized from accumulated other
comprehensive income into net periodic benefit cost during 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
Benefits
|
|
|
|
(In millions)
|
|
|
Net actuarial loss (gain)
|
|
$
|
45
|
|
|
$
|
(1
|
)
|
Prior service cost
|
|
|
4
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
49
|
|
|
$
|
1
|
|
|
|
|
|
|
|
|
|
|
101
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Assumptions
The following table presents the weighted average actuarial
assumptions that were used to determine benefit obligations and
net periodic benefit costs for 2008, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
Pension Benefits
|
|
|
Postretirement Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Assumptions to determine benefit obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
6.00
|
%
|
|
|
6.22
|
%
|
|
|
5.72
|
%
|
|
|
6.00
|
%
|
|
|
6.00
|
%
|
|
|
5.50
|
%
|
Rate of compensation increase
|
|
|
7.00
|
%
|
|
|
7.00
|
%
|
|
|
7.00
|
%
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Assumptions to determine net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
6.18
|
%
|
|
|
5.96
|
%
|
|
|
5.72
|
%
|
|
|
6.00
|
%
|
|
|
5.75
|
%
|
|
|
5.75
|
%
|
Expected return on plan assets
|
|
|
8.40
|
%
|
|
|
8.40
|
%
|
|
|
8.40
|
%
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Rate of compensation increase
|
|
|
7.00
|
%
|
|
|
7.00
|
%
|
|
|
4.50
|
%
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Discount rate Future pension and
postretirement obligations are discounted at the end of each
year based on the rate at which obligations could be effectively
settled, considering the timing of estimated future cash flows
related to the plans. This rate is based on high-quality bond
yields, after allowing for call and default risk. High quality
corporate bond yield indices, such as Moodys Aa, are
considered when selecting the discount rate.
Rate of compensation increase For measurement
of the 2008 and 2007 benefit obligations for the pension plans,
the 7% compensation increase in the table above represents the
assumed increase through 2011. The rate was assumed to decrease
to 5% in the year 2012 and remain at that level thereafter. For
measurement of the 2006 benefit obligation for the pension
plans, the 7% compensation increase in the table above
represents the assumed increase for 2007 and 2008. The rate was
assumed to decrease one percent annually to 5% in the year 2010
and remain at that level thereafter.
Expected return on plan assets Devons
overall investment objective for its retirement plans
assets is to achieve long-term growth of invested capital to
ensure payments of retirement benefits obligations can be funded
when required. To assist in achieving this objective, Devon has
established certain investment strategies, including target
allocation percentages and permitted and prohibited investments,
designed to mitigate risks inherent with investing. At
December 31, 2008, the target investment allocation for
Devons plan assets was 30% U.S. large cap equity
securities; 15% U.S. small cap equity securities, equally
allocated between growth and value; 15% international equity
securities, equally allocated between growth and value; and 40%
debt securities. Derivatives or other speculative investments
considered high-risk are generally prohibited.
The expected rate of return on plan assets was determined by
evaluating input from external consultants and economists as
well as long-term inflation assumptions. Devon expects the
long-term asset allocation to approximate the targeted
allocation. Therefore, the expected long-term rate of return on
plan assets is based on the target allocation of investment
types in such assets.
102
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table presents the weighted-average asset
allocation for Devons pension plans at December 31,
2008 and 2007, and the target allocation for 2009 by asset
category:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Asset category:
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities
|
|
|
60
|
%
|
|
|
59
|
%
|
|
|
83
|
%
|
Debt securities
|
|
|
40
|
%
|
|
|
41
|
%
|
|
|
17
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other assumptions For measurement of the 2008
benefit obligation for the other postretirement medical plans,
an 8.5% annual rate of increase in the per capita cost of
covered health care benefits was assumed for 2009. The rate was
assumed to decrease annually to an ultimate rate of 5% in the
year 2016 and remain at that level thereafter. Assumed health
care cost-trend rates affect the amounts reported for retiree
health care costs. A one-percentage-point change in the assumed
health care cost-trend rates would have the following effects on
the December 31, 2008 other postretirement benefits
obligation and the 2009 service and interest cost components of
net periodic benefit cost.
|
|
|
|
|
|
|
|
|
|
|
One
|
|
|
One
|
|
|
|
Percent
|
|
|
Percent
|
|
|
|
Increase
|
|
|
Decrease
|
|
|
|
(In millions)
|
|
|
Effect on benefit obligation
|
|
$
|
3
|
|
|
$
|
(3
|
)
|
Effect on service and interest costs
|
|
$
|
|
|
|
$
|
|
|
Expected
Cash Flows
The following table presents expected cash flow information for
Devons pension and other postretirement benefit plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
Benefits
|
|
|
|
(In millions)
|
|
|
Devons 2009 contributions
|
|
$
|
183
|
|
|
$
|
5
|
|
Benefit payments:
|
|
|
|
|
|
|
|
|
2009
|
|
$
|
35
|
|
|
$
|
5
|
|
2010
|
|
$
|
35
|
|
|
$
|
5
|
|
2011
|
|
$
|
38
|
|
|
$
|
5
|
|
2012
|
|
$
|
41
|
|
|
$
|
5
|
|
2013
|
|
$
|
46
|
|
|
$
|
5
|
|
2014 to 2018
|
|
$
|
307
|
|
|
$
|
24
|
|
Expected contributions included in the table above include
amounts related to Devons Qualified Plans, Supplemental
Plans and Postretirement Plans. Of the benefits expected to be
paid in 2009, $10 million of pension benefits is expected
to be funded from the trusts established for the Supplemental
Plans and all $5 million of other postretirement benefits
is expected to be funded from Devons available cash and
cash equivalents. Expected employer contributions and benefit
payments for other postretirement benefits are presented net of
employee contributions.
103
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Other
Benefit Plans
Devons 401(k) Plan covers all domestic employees. At its
discretion, Devon may match a certain percentage of the
employees contributions to the plan. The matching
percentage is determined annually by the Board of Directors.
As previously discussed in Revisions to Retirement
Plans above, in 2007 Devon adopted an enhanced defined
contribution structure related to its 401(k) Plan effective
January 1, 2008. Participants who elected to participate in
this enhanced defined contribution structure, as well as all
employees hired on or after October 1, 2007, continue to
receive a discretionary match of a percentage of their
contributions to the 401(k) Plan. These participants also
receive additional, nondiscretionary contributions by Devon
calculated as a percentage of annual compensation. The
percentage will vary based on the employees years of
service.
Devon has defined contribution pension plans for its Canadian
employees. Devon makes a contribution to each employee that is
based upon the employees base compensation and
classification. Such contributions are subject to maximum
amounts allowed under the Income Tax Act (Canada). Devon also
has a savings plan for its Canadian employees. Under the savings
plan, Devon contributes a base percentage amount to all
employees and the employee may elect to contribute an additional
percentage amount (up to a maximum amount) which is matched by
additional Devon contributions.
The following table presents Devons expense related to
these defined contribution plans during 2008, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
401(k) plan
|
|
$
|
21
|
|
|
$
|
18
|
|
|
$
|
15
|
|
Enhanced contribution plan
|
|
|
12
|
|
|
|
|
|
|
|
|
|
Canadian pension and savings plans
|
|
|
16
|
|
|
|
14
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expense
|
|
$
|
49
|
|
|
$
|
32
|
|
|
$
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The authorized capital stock of Devon consists of 1 billion
shares of common stock, par value $0.10 per share, and
4.5 million shares of preferred stock, par value $1.00 per
share. The preferred stock may be issued in one or more series,
and the terms and rights of such stock will be determined by the
Board of Directors.
Devons Board of Directors has designated 2.9 million
shares of the preferred stock as Series A Junior
Participating Preferred Stock (the Series A Junior
Preferred Stock) in connection with the adoption of the
shareholder rights plan described later in this note. At
December 31, 2008, there were no shares of Series A
Junior Preferred Stock issued or outstanding. The Series A
Junior Preferred Stock is entitled to receive cumulative
quarterly dividends per share equal to the greater of $1.00 or
200 times the aggregate per share amount of all dividends (other
than stock dividends) declared on common stock since the
immediately preceding quarterly dividend payment date or, with
respect to the first payment date, since the first issuance of
Series A Junior Preferred Stock. Holders of the
Series A Junior Preferred Stock are entitled to 200 votes
per share (subject to adjustment to prevent dilution) on all
matters submitted to a vote of the stockholders. The
Series A Junior Preferred Stock is neither redeemable nor
convertible. The Series A Junior Preferred Stock ranks
prior to the common stock but junior to all other classes of
Preferred Stock.
104
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Preferred
Stock Redemption
On June 20, 2008, Devon redeemed all 1.5 million
outstanding shares of its 6.49% Series A cumulative
preferred stock. Each share of preferred stock was redeemed for
cash at a redemption price of $100 per share, plus accrued and
unpaid dividends up to the redemption date.
Stock
Repurchases
Devons Board of Directors has approved an ongoing, annual
stock repurchase program to minimize dilution resulting from
restricted stock issued to, and options exercised by, employees.
Also, Devons Board of Directors approved a program in 2007
to repurchase up to 50 million shares. This program expires
on December 31, 2009 and was created as a potential use of
the proceeds received from Devons West African property
divestitures. Devons Board of Directors also approved a
separate 50 million share repurchase program in August
2005, which expired on December 31, 2007.
In response to the current economic environment and recent
downturn in commodity prices, Devon has indefinitely suspended
activity under its authorized programs. As a result, Devon does
not anticipate repurchasing shares under these programs in the
foreseeable future. Should economic conditions or commodity
prices strengthen, Devon will consider resumption of share
repurchases under its authorized programs.
During the three-year period ended December 31, 2008, Devon
repurchased 14.8 million shares at a total cost of
$1.2 billion, or $83.98 per share, under these repurchase
programs. The following table summarizes Devons
repurchases under these plans during 2008, 2007 and 2006
(amounts and shares in millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Repurchase Program
|
|
Amount
|
|
|
Shares
|
|
|
Per Share
|
|
|
Amount
|
|
|
Shares
|
|
|
Per Share
|
|
|
Amount
|
|
|
Shares
|
|
|
Per Share
|
|
|
Annual program
|
|
$
|
178
|
|
|
|
2.0
|
|
|
$
|
87.83
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
2007 program
|
|
|
487
|
|
|
|
4.5
|
|
|
$
|
109.25
|
|
|
|
326
|
|
|
|
4.1
|
|
|
$
|
79.80
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
2005 program
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
253
|
|
|
|
4.2
|
|
|
$
|
59.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
$
|
665
|
|
|
|
6.5
|
|
|
$
|
102.56
|
|
|
$
|
326
|
|
|
|
4.1
|
|
|
$
|
79.80
|
|
|
$
|
253
|
|
|
|
4.2
|
|
|
$
|
59.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholder
Rights Plan
Under Devons shareholder rights plan, stockholders have
one-half of one right for each share of common stock held. The
rights become exercisable and separately transferable ten
business days after (a) an announcement that a person has
acquired, or obtained the right to acquire, 15% or more of the
voting shares outstanding, or (b) commencement of a tender
or exchange offer that could result in a person owning 15% or
more of the voting shares outstanding.
Each right entitles its holder (except a holder who is the
acquiring person) to purchase either (a) 1/100 of a share
of Series A Preferred Stock for $185.00, subject to
adjustment or, (b) Devon common stock with a value equal to
twice the exercise price of the right, subject to adjustment to
prevent dilution. In the event of certain merger or asset sale
transactions with another party or transactions that would
increase the equity ownership of a shareholder who then owned
15% or more of Devon, each Devon right will entitle its holder
to purchase securities of the merging or acquiring party with a
value equal to twice the exercise price of the right.
The rights, which have no voting power, expire on
August 17, 2009. The rights may be redeemed by Devon for
$0.01 per right until the rights become exercisable.
105
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Dividends
Devon paid common stock dividends of $284 million (or $0.64
per share), $249 million (or $0.56 per share) and
$199 million (or $0.45 per share) in 2008, 2007 and 2006
respectively. Devon paid dividends of $5 million in 2008
and $10 million in both 2007 and 2006 to preferred
stockholders. The decrease in preferred stock dividend in 2008
is due to the redemption of the preferred stock in the second
quarter of 2008.
|
|
10.
|
Commitments
and Contingencies
|
Devon is party to various legal actions arising in the normal
course of business. Matters that are probable of unfavorable
outcome to Devon and which can be reasonably estimated are
accrued. Such accruals are based on information known about the
matters, Devons estimates of the outcomes of such matters
and its experience in contesting, litigating and settling
similar matters. None of the actions are believed by management
to involve future amounts that would be material to Devons
financial position or results of operations after consideration
of recorded accruals although actual amounts could differ
materially from managements estimate.
Environmental
Matters
Devon is subject to certain laws and regulations relating to
environmental remediation activities associated with past
operations, such as the Comprehensive Environmental Response,
Compensation, and Liability Act (CERCLA) and similar
state statutes. In response to liabilities associated with these
activities, accruals have been established when reasonable
estimates are possible. Such accruals primarily include
estimated costs associated with remediation. Devon has not used
discounting in determining its accrued liabilities for
environmental remediation, and no material claims for possible
recovery from third-party insurers or other parties related to
environmental costs have been recognized in Devons
consolidated financial statements. Devon adjusts the accruals
when new remediation responsibilities are discovered and
probable costs become estimable, or when current remediation
estimates must be adjusted to reflect new information.
Certain of Devons subsidiaries acquired in past mergers
are involved in matters in which it has been alleged that such
subsidiaries are potentially responsible parties
(PRPs) under CERCLA or similar state legislation
with respect to various waste disposal areas owned or operated
by third parties. As of December 31, 2008, Devons
balance sheet included $1 million of noncurrent accrued
liabilities, reflected in other liabilities, related to these
and other environmental remediation liabilities. Devon does not
currently believe there is a reasonable possibility of incurring
additional material costs in excess of the current accruals
recognized for such environmental remediation activities. With
respect to the sites in which Devon subsidiaries are PRPs,
Devons conclusion is based in large part on
(i) Devons participation in consent decrees with both
other PRPs and the Environmental Protection Agency, which
provide for performing the scope of work required for
remediation and contain covenants not to sue as protection to
the PRPs, (ii) participation in groups as a de minimis
PRP, and (iii) the availability of other
defenses to liability. As a result, Devons monetary
exposure is not expected to be material.
Royalty
Matters
Numerous natural gas producers and related parties, including
Devon, have been named in various lawsuits alleging violation of
the federal False Claims Act. The suits allege that the
producers and related parties used below-market prices, improper
deductions, improper measurement techniques and transactions
with affiliates, which resulted in underpayment of royalties in
connection with natural gas and NGLs produced and sold from
federal and Indian owned or controlled lands. The principal suit
in which Devon is a defendant is United States ex rel.
Wright v. Chevron USA, Inc. et al. (the Wright
case). The suit was originally filed in August 1996 in the
United States District Court for the Eastern District of Texas,
but was consolidated in October 2000 with other suits for
pre-trial proceedings in the United States District Court for
the District of
106
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Wyoming. On July 10, 2003, the District of Wyoming remanded
the Wright case back to the Eastern District of Texas to resume
proceedings. On April 12, 2007, the court entered a trial
plan and scheduling order in which the case will proceed in
phases. Two phases have been scheduled to date. The first phase
was scheduled to begin in August 2008, but the defendant settled
prior to trial. The second phase was scheduled to begin in
February 2009, but the defendants settled prior to trial. Devon
was not included in the groups of defendants selected for these
first two phases. Devon believes that it has acted reasonably,
has legitimate and strong defenses to all allegations in the
suit, and has paid royalties in good faith. Devon does not
currently believe that it is subject to material exposure with
respect to this lawsuit and, therefore, no liability related to
this lawsuit has been recorded.
In 1995, the United States Congress passed the Deep Water
Royalty Relief Act. The intent of this legislation was to
encourage deep water exploration in the Gulf of Mexico by
providing relief from the obligation to pay royalties on certain
federal leases. Deep water leases issued in certain years by the
Minerals Management Service (the MMS) have contained
price thresholds, such that if the market prices for oil or gas
exceeded the thresholds for a given year, royalty relief would
not be granted for that year. Deep water leases issued in 1998
and 1999 did not include price thresholds.
The U.S. House of Representatives in January 2007 passed
legislation that would have required companies to renegotiate
the 1998 and 1999 leases as a condition of securing future
federal leases. This legislation was not passed by the
U.S. Senate. However, Congress may consider similar
legislation in the future. In October 2007 a federal district
court ruled in favor of a plaintiff who had challenged the
legality of including price thresholds in deep water leases.
Additionally, in January 2009 a federal appellate court upheld
this district court ruling. This judgment is subject to further
appeals.
As of December 31, 2008, Devon had $83 million accrued
for potential royalties on various deep water leases. Due to the
uncertainty of this issue caused by the favorable federal court
decisions and potential Congressional actions, Devon has ceased
accruing additional royalties on its affected leases. Devon will
continue to monitor developments and adjust its accruals as
necessary.
Hurricane
Contingencies
Prior to September 1, 2006, Devon maintained a
comprehensive insurance program that included coverage for
physical damage to its offshore facilities caused by hurricanes.
This program also included substantial business interruption
coverage, which entitled Devon to be reimbursed for the portion
of production suspended longer than forty-five days, subject to
upper limits to oil and gas prices. Also, the terms of the
historical insurance included a standard, per-event deductible
of $1 million for offshore losses as well as a
$15 million aggregate annual deductible.
Devon suffered insured damages in the third quarter of 2005
related to hurricanes that struck the Gulf of Mexico. During
2006 and 2007, Devon received $480 million as a full
settlement of the amount due from its primary insurers and
certain of its secondary insurers. During the fourth quarter of
2008, Devon received $106 million as full settlement of the
amount due from its remaining secondary insurers. Devons
claims under its then existing insurance arrangements included
both physical damages and business interruption claims. As of
December 31, 2008, Devon had used $424 million of
these proceeds as reimbursement of repair costs and deductible
amounts, resulting in excess recoveries. The $162 million
of excess recoveries was recorded as other income in the
accompanying statement of operations during 2008.
The policy underlying the insurance program terms described
above expired on August 31, 2006. Due to significant
changes in the insurance marketplace, Devon no longer has
coverage for damage that may be caused by named windstorms from
the Gulf of Mexico. As a result, Devons current insurance
program includes coverage for physical damage and business
interruption but does not have such coverage for damages or
business interruption caused from named windstorms.
107
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
During the third quarter of 2008, Hurricanes Ike and Gustav
damaged certain of Devons oil and gas facilities and
transportation systems in the Gulf of Mexico. These damages
relate to both production operations that will be repaired and
restored and production operations that will not be restored.
These damages are uninsured losses because they resulted from
named windstorms.
For the damaged facilities and transportation systems for which
Devon intends to resume operations after repairs have been made,
a loss of $31 million was recognized in 2008. This loss is
included in lease operating expenses in the accompanying
statement of operations.
The facilities for which Devon will not restore production
operations consist of certain platforms that were completely
destroyed. Devon has begun performing asset retirement
activities associated with the destroyed platforms and related
wells. The time and effort required to complete such activities
is expected to be significant due to the hazardous conditions
created by the hurricanes. As a result, the estimated costs to
complete the asset retirement activities are $82 million
higher than Devons previously estimated asset retirement
obligations related to the destroyed platforms and related
wells. Therefore, in 2008, Devon increased its asset retirement
obligations by $82 million with a corresponding increase to
oil and gas property and equipment in the accompanying balance
sheet. Based on the projected timing of the retirement
activities, half of this asset retirement obligation increase
was recorded to the current portion and half was recorded to the
long-term portion.
Other
Matters
Devon is involved in other various routine legal proceedings
incidental to its business. However, to Devons knowledge
as of the date of this report, there were no other material
pending legal proceedings to which Devon is a party or to which
any of its property is subject.
Commitments
Devon has certain drilling and facility obligations under
contractual agreements with third-party service providers to
procure drilling rigs and other related services for
developmental and exploratory drilling and facilities
construction. Included in the $3.7 billion total of
Drilling and Facility Obligations in the table below
is $1.7 billion that relates to long-term contracts for
three deepwater drilling rigs and certain other contracts for
onshore drilling and facility obligations in which drilling or
facilities construction has not commenced. The $1.7 billion
represents the gross commitment under these contracts.
Devons ultimate payment for these commitments will be
reduced by the amounts billed to its partners when net working
interests are ultimately determined. Payments for these
commitments, net of amounts billed to partners, will be
capitalized as a component of oil and gas properties.
Devon has certain firm transportation agreements that represent
ship or pay arrangements whereby Devon has committed
to ship certain volumes of oil, gas and NGLs for a fixed
transportation fee. Devon has entered into these agreements to
aid the movement of its production to market. Devon expects to
have sufficient production to utilize the majority of these
transportation services.
Devon leases certain office space and equipment under operating
lease arrangements. Total rental expense included in general and
administrative expenses under operating leases, net of
sub-lease
income, was $46 million, $43 million and
$36 million in 2008, 2007 and 2006, respectively.
Devon assumed two offshore platform spar leases through the 2003
Ocean merger. The spars are being used in the development of the
Nansen and Boomvang fields in the Gulf of Mexico. The Boomvang
field was divested as part of the 2005 property divestiture
program. The Nansen operating lease is for a
20-year term
and contains various options whereby Devon may purchase the
lessors interests in the spar. Total rental expense
included in lease operating expenses under the Nansen operating
lease was $12 million in 2008, 2007 and 2006, respectively.
Devon has guaranteed that the Nansen spar will have a residual
value at the end of the
108
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
operating lease equal to at least 10% of the fair value of the
spar at the inception of the lease. The total guaranteed value
is $14 million in 2022. However, such amount may be reduced
under the terms of the lease agreement. As a result of the sale
of the Boomvang field, Devon is subleasing the Boomvang Spar. If
the sublessee were to default on its obligation, Devon would
continue to be obligated to pay the periodic lease payments and
any guaranteed value required at the end of the term.
Devon has a floating, production, storage and offloading
facility (FPSO) that is being used in the Panyu
project offshore China and is being leased under operating lease
arrangements. This lease expires in September 2009. Devon is
also leasing an FPSO that is being used in the Polvo project
offshore Brazil. This lease expires in 2014. Devon expects to
begin production from its Cascade development in the Gulf of
Mexico in 2010. As a result, Devon has entered into a contract
to lease an FPSO. This lease expires in 2015. Total rental
expense included in lease operating expenses under the China and
Brazil operating leases was $25 million, $17 million
and $9 million in 2008, 2007 and 2006, respectively.
The following is a schedule by year of future minimum payments
for drilling and facility obligations, firm transportation
agreements and leases that have initial or remaining
noncancelable lease terms in excess of one year as of
December 31, 2008. The schedule includes $42 million
of drilling and facility obligations related to Devons
discontinued operations (see Note 16).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
|
|
|
Firm
|
|
|
Office and
|
|
|
|
|
|
|
|
|
|
and Facility
|
|
|
Transportation
|
|
|
Equipment
|
|
|
Spar
|
|
|
FPSO
|
|
Year Ending December 31,
|
|
Obligations
|
|
|
Agreements
|
|
|
Leases
|
|
|
Leases
|
|
|
Leases
|
|
|
|
(In millions)
|
|
|
2009
|
|
$
|
1,423
|
|
|
$
|
273
|
|
|
$
|
57
|
|
|
$
|
11
|
|
|
$
|
37
|
|
2010
|
|
|
897
|
|
|
|
271
|
|
|
|
41
|
|
|
|
11
|
|
|
|
59
|
|
2011
|
|
|
575
|
|
|
|
245
|
|
|
|
37
|
|
|
|
11
|
|
|
|
54
|
|
2012
|
|
|
387
|
|
|
|
223
|
|
|
|
33
|
|
|
|
22
|
|
|
|
54
|
|
2013
|
|
|
352
|
|
|
|
198
|
|
|
|
30
|
|
|
|
13
|
|
|
|
54
|
|
Thereafter
|
|
|
101
|
|
|
|
784
|
|
|
|
163
|
|
|
|
105
|
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total payments
|
|
$
|
3,735
|
|
|
$
|
1,994
|
|
|
$
|
361
|
|
|
$
|
173
|
|
|
$
|
299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.
|
Fair
Value Measurements
|
Certain of Devons assets and liabilities are reported at
fair value in the accompanying balance sheets. Such assets and
liabilities include amounts for both financial and nonfinancial
instruments. The following tables provide fair value measurement
information for such assets and liabilities as of
December 31, 2008 and 2007.
109
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The carrying values of cash and cash equivalents, accounts
receivable and accounts payable (including income taxes payable
and accrued expenses) included in the accompanying consolidated
balance sheets approximated fair value at December 31, 2008
and 2007. These assets and liabilities are not presented in the
following tables.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
|
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
Total
|
|
|
in Active
|
|
|
Other Observable
|
|
|
Unobservable
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
Amount
|
|
|
Value
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
|
(In millions)
|
|
|
Financial Assets (Liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term investments
|
|
$
|
122
|
|
|
$
|
122
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
122
|
|
Gas price collars
|
|
$
|
255
|
|
|
$
|
255
|
|
|
$
|
|
|
|
$
|
255
|
|
|
$
|
|
|
Interest rate swaps
|
|
$
|
104
|
|
|
$
|
104
|
|
|
$
|
|
|
|
$
|
104
|
|
|
$
|
|
|
Debt
|
|
$
|
(5,841
|
)
|
|
$
|
(6,106
|
)
|
|
$
|
(1,005
|
)
|
|
$
|
(5,101
|
)
|
|
$
|
|
|
Asset retirement obligations
|
|
$
|
(1,485
|
)
|
|
$
|
(1,485
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(1,485
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
|
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Significant Other
|
|
|
Significant
|
|
|
|
|
|
|
Total
|
|
|
in Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
Amount
|
|
|
Value
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
|
(In millions)
|
|
|
Financial Assets (Liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments
|
|
$
|
372
|
|
|
$
|
372
|
|
|
$
|
372
|
|
|
$
|
|
|
|
$
|
|
|
Investment in Chevron common stock
|
|
$
|
1,324
|
|
|
$
|
1,324
|
|
|
$
|
1,324
|
|
|
$
|
|
|
|
$
|
|
|
Gas price swaps
|
|
$
|
12
|
|
|
$
|
12
|
|
|
$
|
|
|
|
$
|
12
|
|
|
$
|
|
|
Embedded option in exchangeable debentures
|
|
$
|
(488
|
)
|
|
$
|
(488
|
)
|
|
$
|
|
|
|
$
|
(488
|
)
|
|
$
|
|
|
Debt
|
|
$
|
(7,928
|
)
|
|
$
|
(9,055
|
)
|
|
$
|
(1,140
|
)
|
|
$
|
(7,915
|
)
|
|
$
|
|
|
Asset retirement obligations
|
|
$
|
(1,318
|
)
|
|
$
|
(1,318
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(1,318
|
)
|
The fair values are classified according to a hierarchy that
prioritizes the inputs to valuation techniques used to measure
fair value. As presented in the table above, this hierarchy
consists of three broad levels. Level 1 inputs on the
hierarchy consist of unadjusted quoted prices in active markets
for identical assets and liabilities and have the highest
priority. Level 3 inputs have the lowest priority. Devon
uses appropriate valuation techniques based on the available
inputs to measure the fair values of its assets and liabilities.
When available, Devon measures fair value using Level 1
inputs because they generally provide the most reliable evidence
of fair value. The following methods and assumptions were used
to estimate the fair values of the assets and liabilities in the
table above.
Level 1
Fair Value Measurements
Investment in Chevron Corporation common
stock The fair value of this investment is based
on a quoted market price.
Debt The fair value of Devons
variable-rate commercial paper borrowings is the carrying value.
Certain of Devons fixed-rate debt instruments actively
trade in an established market. The fair values of this debt are
based on quotes obtained from brokers.
110
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Level 2
Fair Value Measurements
Gas price swaps and collars The fair values
of the gas price swaps and collars are estimated using internal
discounted cash flow calculations based upon forward commodity
price curves, quotes obtained from brokers for contracts with
similar terms or quotes obtained from counterparties to the
agreements.
Embedded option in exchangeable debentures
The embedded option was not actively traded in an established
market. Therefore, its fair value was estimated using quotes
obtained from a broker for trades near the fair value
measurement date.
Debt Certain of Devons fixed-rate debt
instruments do not actively trade in an established market. The
fair values of this debt are estimated by discounting the
principal and interest payments at rates available for debt with
similar terms and maturity.
Interest rate swaps The fair values of the
interest rate swaps are estimated using internal discounted cash
flow calculations based upon forward interest-rate yield curves
or quotes obtained from counterparties to the agreements.
Level 3
Fair Value Measurements
Asset retirement obligations The fair values
of the asset retirement obligations are estimated using internal
discounted cash flow calculations based upon Devons
estimates of future retirement costs. Reconciliations of the
beginning and ending balances of Devons asset retirement
obligations, including revisions of the estimated fair values in
2008 and 2007, are presented in Note 5.
Short-term and long-term investments
Devons short-term and long-term investments presented in
the tables above as of December 31, 2008 and
December 31, 2007 consisted entirely of auction rate
securities. As of December 31, 2007, Devon estimated the
fair values of its short-term investments using quoted market
prices. However, due to the auction failures discussed in
Note 1 and the lack of an active market for Devons
auction rate securities, quoted market prices for these
securities were not available as of December 31, 2008.
Therefore, Devon used valuation techniques that rely on
unobservable, or Level 3, inputs to estimate the fair
values of its long-term auction rate securities as of
December 31, 2008. These inputs were based on the AAA
credit rating of the securities, the probability of full
repayment of the securities considering the United States
government guarantees of substantially all of the underlying
student loans, the collection of all accrued interest to date
and continued receipts of principal at par. Devon also has the
ability to hold these securities until their scheduled maturity
dates. As a result of using these inputs, Devon concluded the
estimated fair values of its long-term auction rate securities
approximated the par values as of December 31, 2008. At
this time, Devon does not believe the values of its long-term
securities are impaired.
Included below is a summary of the changes in Devons
Level 3 short-term and long-term investments during 2008
(in millions).
|
|
|
|
|
Beginning balance
|
|
$
|
|
|
Transfers from Level 1 to Level 3
|
|
|
129
|
|
Redemptions of principal
|
|
|
(7
|
)
|
|
|
|
|
|
Ending balance
|
|
$
|
122
|
|
|
|
|
|
|
|
|
12.
|
Share-Based
Compensation
|
On June 8, 2005, Devons stockholders adopted the 2005
Long-Term Incentive Plan, which expires on June 8, 2013.
Devons stockholders adopted certain amendments to this
plan on June 7, 2006. This plan, as amended, authorizes the
Compensation Committee, which consists of non-management members
of Devons Board of Directors, to grant nonqualified and
incentive stock options, restricted stock awards, Canadian
111
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
restricted stock units, performance units, performance bonuses,
stock appreciation rights and cash-out rights to eligible
employees. The plan also authorizes the grant of nonqualified
stock options, restricted stock awards and stock appreciation
rights to directors. A total of 32 million shares of Devon
common stock have been reserved for issuance pursuant to the
plan. To calculate shares issued under the plan, options granted
represent one share and other awards represent 2.2 shares.
Devon also has stock option plans that were adopted in 2003 and
1997 under which stock options and restricted stock awards were
issued to key management and professional employees. Options
granted under these plans remain exercisable by the employees
owning such options, but no new options or restricted stock
awards will be granted under these plans. Devon also has stock
options outstanding that were assumed as part of the
acquisitions of Ocean, Mitchell Energy & Development
Corp., Santa Fe Snyder and PennzEnergy.
With the approval of Devons Compensation Committee, Devon
modified the share-based compensation arrangements for certain
of Devons executives in the second quarter of 2008. The
modified compensation arrangements provide that executives who
meet certain
years-of-service
and age criteria can retire and continue vesting in outstanding
share-based grants. As a condition to receiving the benefits of
these modifications, the executives must agree not to use or
disclose Devons confidential information and not to
solicit Devons employees and customers. The executives are
required to agree to these conditions at retirement and again in
each subsequent year until all grants have vested.
Although this modification does not accelerate the vesting of
the executives grants, it does accelerate the expense
recognition as executives approach the
years-of-service
and age criteria. When the modification was made in the second
quarter of 2008, certain executives had already met the
years-of-service
and age criteria. As a result, Devon recognized an additional
$27 million of share-based compensation expense in the
second quarter of 2008 related to this modification. This
additional expense would have been recognized in future
reporting periods if the modification had not been made and the
executives continued their employment at Devon.
The following table presents the effects of share-based
compensation included in Devons accompanying statement of
operations for the years ended December 31, 2008, 2007 and
2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Gross general and administrative expense
|
|
$
|
225
|
|
|
$
|
146
|
|
|
$
|
91
|
|
Share-based compensation expense capitalized pursuant to the
full cost method of accounting for oil and gas properties
|
|
$
|
53
|
|
|
$
|
44
|
|
|
$
|
26
|
|
Related income tax benefit
|
|
$
|
62
|
|
|
$
|
34
|
|
|
$
|
23
|
|
Stock
Options
Under Devons 2005 Long-Term Incentive Plan, the exercise
price of stock options granted may not be less than the
estimated fair market value of the stock at the date of grant.
In addition, options granted are exercisable during a period
established for each grant, which may not exceed eight years
from the date of grant. The recipient must pay the exercise
price in cash or in common stock, or a combination thereof, at
the time that the option is exercised. Options granted generally
have a vesting period that ranges from three to four years.
The fair value of stock options on the date of grant is expensed
over the applicable vesting period. Devon estimates the fair
values of stock options granted using a Black-Scholes option
valuation model, which requires Devon to make several
assumptions. The volatility of Devons common stock is
based on the historical volatility of the market price of
Devons common stock over a period of time equal to the
expected term of the option and ending on the grant date. The
dividend yield is based on Devons historical and current
yield in effect at the date of grant. The risk-free interest
rate is based on the zero-coupon U.S. Treasury yield
112
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
for the expected term of the option at the date of grant. The
expected term of the options is based on historical exercise and
termination experience for various groups of employees and
directors. Each group is determined based on the similarity of
their historical exercise and termination behavior.
The following table presents a summary of the grant-date fair
values of stock options granted and the related assumptions for
the years ended December 31, 2008, 2007 and 2006. All such
amounts represent the weighted-average amounts for each year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Grant-date fair value
|
|
$
|
21.77
|
|
|
$
|
26.43
|
|
|
$
|
22.41
|
|
Volatility factor
|
|
|
44.3
|
%
|
|
|
31.6
|
%
|
|
|
32.2
|
%
|
Dividend yield
|
|
|
0.9
|
%
|
|
|
0.7
|
%
|
|
|
0.5
|
%
|
Risk-free interest rate
|
|
|
1.2
|
%
|
|
|
5.0
|
%
|
|
|
5.7
|
%
|
Expected term (in years)
|
|
|
3.8
|
|
|
|
4.0
|
|
|
|
4.0
|
|
The following table presents a summary of Devons
outstanding stock options as of December 31, 2008,
including changes during the year then ended.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Remaining
|
|
|
Aggregate
|
|
|
|
|
|
|
Exercise
|
|
|
Contractual
|
|
|
Intrinsic
|
|
|
|
Options
|
|
|
Price
|
|
|
Term
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
|
|
|
(In Years)
|
|
|
(In millions)
|
|
|
Outstanding at December 31, 2007
|
|
|
13,806
|
|
|
$
|
46.66
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
2,175
|
|
|
$
|
67.56
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(3,918
|
)
|
|
$
|
31.56
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(169
|
)
|
|
$
|
68.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
11,894
|
|
|
$
|
55.16
|
|
|
|
3.8
|
|
|
$
|
180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested and expected to vest at December 31, 2008
|
|
|
11,840
|
|
|
$
|
55.08
|
|
|
|
3.8
|
|
|
$
|
180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2008
|
|
|
8,108
|
|
|
$
|
46.35
|
|
|
|
3.1
|
|
|
$
|
179
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic value of stock options that were
exercised during 2008, 2007 and 2006 was $263 million,
$151 million and $119 million, respectively. As of
December 31, 2008, Devons unrecognized compensation
cost related to unvested stock options was $69 million.
Such cost is expected to be recognized over a weighted-average
period of 2.5 years.
Restricted
Stock Awards and Units
Under Devons 2005 Long-Term Incentive Plan, restricted
stock awards and units are subject to the terms, conditions,
restrictions and limitations, if any, that the Compensation
Committee deems appropriate, including restrictions on continued
employment. Generally, restricted stock awards and units vest
over a minimum restriction period of at least three years from
the date of grant. During the vesting period, recipients of
restricted stock awards receive dividends that are not subject
to restrictions or other limitations. The fair value of
restricted stock awards and units on the date of grant is
expensed over the applicable vesting period. Devon estimates the
fair values of restricted stock awards and units as the closing
price of Devons common stock on the grant date of the
award or unit.
113
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table presents a summary of Devons unvested
restricted stock awards as of December 31, 2008, including
changes during the year then ended.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Restricted
|
|
|
Average
|
|
|
|
Stock
|
|
|
Grant-Date
|
|
|
|
Awards
|
|
|
Fair Value
|
|
|
|
(In thousands)
|
|
|
|
|
|
Unvested at December 31, 2007
|
|
|
5,426
|
|
|
$
|
71.38
|
|
Granted
|
|
|
3,283
|
|
|
$
|
69.48
|
|
Vested
|
|
|
(2,222
|
)
|
|
$
|
64.66
|
|
Forfeited
|
|
|
(153
|
)
|
|
$
|
71.33
|
|
|
|
|
|
|
|
|
|
|
Unvested at December 31, 2008
|
|
|
6,334
|
|
|
$
|
72.66
|
|
|
|
|
|
|
|
|
|
|
The aggregate fair value of restricted stock awards that vested
during 2008, 2007 and 2006 was $185 million,
$136 million and $82 million, respectively. As of
December 31, 2008, Devons unrecognized compensation
cost related to unvested restricted stock awards and units was
$402 million. Such cost is expected to be recognized over a
weighted-average period of 3.0 years.
|
|
13.
|
Reduction
of Carrying Value of Oil and Gas Properties
|
During 2008 and 2006, Devon reduced the carrying values of
certain of its oil and gas properties due to full cost ceiling
limitations and unsuccessful exploratory activities. A summary
of these reductions and additional discussion is provided below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2006
|
|
|
|
|
|
|
Net of
|
|
|
|
|
|
Net of
|
|
|
|
Gross
|
|
|
Taxes
|
|
|
Gross
|
|
|
Taxes
|
|
|
|
(In millions)
|
|
|
Full cost ceiling limitations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
6,538
|
|
|
$
|
4,168
|
|
|
$
|
|
|
|
$
|
|
|
Canada
|
|
|
3,353
|
|
|
|
2,488
|
|
|
|
|
|
|
|
|
|
Brazil
|
|
|
437
|
|
|
|
437
|
|
|
|
|
|
|
|
|
|
Russia
|
|
|
36
|
|
|
|
17
|
|
|
|
20
|
|
|
|
10
|
|
Indonesia
|
|
|
15
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
Unsuccessful exploratory activities Brazil
|
|
|
|
|
|
|
|
|
|
|
16
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,379
|
|
|
$
|
7,115
|
|
|
$
|
36
|
|
|
$
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
114
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
2008
Reductions
The 2008 reductions were all recognized in the fourth quarter of
2008 and resulted primarily from a significant decrease in each
countrys full cost ceiling. The lower ceiling values
largely resulted from the effects of sharp declines in oil, gas
and NGL prices compared to previous quarter-end prices. To
demonstrate this decline, the December 31, 2008 and
September 30, 2008 weighted average wellhead prices for the
United States, Canada and Brazil are presented in the following
table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
September 30, 2008
|
|
Country
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
United States
|
|
$
|
42.21
|
|
|
$
|
4.68
|
|
|
$
|
16.16
|
|
|
$
|
97.62
|
|
|
$
|
5.28
|
|
|
$
|
38.00
|
|
Canada
|
|
$
|
23.23
|
|
|
$
|
5.31
|
|
|
$
|
20.89
|
|
|
$
|
59.72
|
|
|
$
|
6.00
|
|
|
$
|
62.78
|
|
Brazil
|
|
$
|
26.61
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
$
|
81.56
|
|
|
|
N/A
|
|
|
|
N/A
|
|
N/A Not applicable.
The December 31, 2008 oil and gas wellhead prices in the
table above compare to the NYMEX cash price of $44.60 per Bbl
for crude oil and the Henry Hub spot price of $5.71 per MMBtu
for gas. The September 30, 2008, wellhead prices in the
table compare to the NYMEX cash price of $100.64 per Bbl for
crude oil and the Henry Hub spot price of $7.12 per MMBtu for
gas.
2006
Reductions
As a result of a decline in the estimated future net revenues,
the carrying value of Devons Russian oil and gas
properties exceeded the full cost ceiling by $10 million at
the end of the third quarter of 2006. Therefore, Devon
recognized a $20 million reduction of the carrying value of
its oil and gas properties in Russia, offset by a
$10 million deferred income tax benefit.
During the second quarter of 2006, Devon drilled two
unsuccessful exploratory wells in Brazil and determined that the
capitalized costs related to these two wells should be impaired.
Therefore, in the second quarter of 2006, Devon recognized a
$16 million impairment of its investment in Brazil equal to
the costs to drill the two dry holes and a proportionate share
of block-related costs. There was no tax benefit related to this
impairment. The two wells were unrelated to Devons Polvo
development project in Brazil.
The components of other income include the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Interest and dividend income
|
|
$
|
75
|
|
|
$
|
89
|
|
|
$
|
100
|
|
Hurricane insurance proceeds
|
|
|
162
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
(13
|
)
|
|
|
9
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
224
|
|
|
$
|
98
|
|
|
$
|
115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
115
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Income
Tax (Benefit) Expense
The (loss) earnings from continuing operations before income
taxes and the components of income tax expense (benefit) for the
years 2008, 2007 and 2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
(Loss) earnings from continuing operations before income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
(2,190
|
)
|
|
$
|
2,642
|
|
|
$
|
2,435
|
|
Canada
|
|
|
(1,970
|
)
|
|
|
685
|
|
|
|
751
|
|
International
|
|
|
127
|
|
|
|
897
|
|
|
|
384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(4,033
|
)
|
|
$
|
4,224
|
|
|
$
|
3,570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income tax expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
$
|
258
|
|
|
$
|
83
|
|
|
$
|
292
|
|
Various states
|
|
|
31
|
|
|
|
16
|
|
|
|
7
|
|
Canada and various provinces
|
|
|
152
|
|
|
|
136
|
|
|
|
143
|
|
International
|
|
|
178
|
|
|
|
265
|
|
|
|
86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current tax expense
|
|
|
619
|
|
|
|
500
|
|
|
|
528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax (benefit) expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
|
(875
|
)
|
|
|
745
|
|
|
|
456
|
|
Various states
|
|
|
(65
|
)
|
|
|
28
|
|
|
|
77
|
|
Canada and various provinces
|
|
|
(622
|
)
|
|
|
(166
|
)
|
|
|
(105
|
)
|
International
|
|
|
(11
|
)
|
|
|
(29
|
)
|
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax (benefit) expense
|
|
|
(1,573
|
)
|
|
|
578
|
|
|
|
408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax (benefit) expense
|
|
$
|
(954
|
)
|
|
$
|
1,078
|
|
|
$
|
936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The taxes on the results of discontinued operations presented in
the accompanying statements of operations were all related to
international operations.
Total income tax expense differed from the amounts computed by
applying the U.S. federal income tax rate to earnings from
continuing operations before income taxes as a result of the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Expected income tax (benefit) expense based on U.S. statutory
tax rate of 35%
|
|
$
|
(1,411
|
)
|
|
$
|
1,478
|
|
|
$
|
1,249
|
|
Effect of Canadian tax rate reductions
|
|
|
(7
|
)
|
|
|
(261
|
)
|
|
|
(243
|
)
|
State income taxes
|
|
|
(29
|
)
|
|
|
30
|
|
|
|
55
|
|
Repatriations and tax policy election changes
|
|
|
307
|
|
|
|
|
|
|
|
|
|
Taxation on foreign operations
|
|
|
206
|
|
|
|
(165
|
)
|
|
|
(120
|
)
|
Other
|
|
|
(20
|
)
|
|
|
(4
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax (benefit) expense
|
|
$
|
(954
|
)
|
|
$
|
1,078
|
|
|
$
|
936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
116
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In 2008, 2007 and 2006, deferred income taxes were reduced
$7 million, $261 million and $243 million,
respectively, due to successive Canadian statutory rate
reductions that were enacted in each such year.
In 2006, deferred income taxes increased $39 million due to
the effect of a new income-based tax enacted by the state of
Texas that replaced a previous franchise tax. The new tax was
effective January 1, 2007. The $39 million increase is
included in 2006 state income taxes in the above table.
During 2008, Devon repatriated $2.6 billion from certain
foreign subsidiaries to the United States. Subsequent to these
repatriations, Devon does not expect to repatriate similar
earnings from its historical operations in the foreseeable
future. Also in the second quarter of 2008, Devon made certain
tax policy election changes to minimize the taxes Devon
otherwise would pay for the cash repatriations, as well as the
taxable gains associated with the sales of assets in West Africa.
As a result of the repatriations, as well as the tax policy
election changes, Devon recognized additional tax expense of
$307 million during 2008. Of the $307 million,
$290 million was recognized as current income tax expense,
and $17 million was recognized as deferred tax expense.
Deferred
Tax Assets and Liabilities
At December 31, 2008, Devon had the following net operating
loss carryforwards, which are available to reduce future taxable
income in the jurisdiction where the net operating loss was
incurred. These carryforwards will result in a future tax
reduction based upon the future tax rate applicable to the
taxable income that is ultimately offset by the net operating
loss carryforward. For financial purposes, the tax effects of
these carryforwards, net of any valuation allowances, have been
recognized as reductions to the net deferred tax liability at
December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
Years of
|
|
|
Carryforward
|
|
Jurisdiction
|
|
Expiration
|
|
|
Amounts
|
|
|
|
|
|
|
(In millions)
|
|
|
Various U.S. states
|
|
|
2009 2022
|
|
|
$
|
87
|
|
Canada
|
|
|
2025 2027
|
|
|
$
|
20
|
|
Brazil
|
|
|
Indefinite
|
|
|
$
|
179
|
|
117
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The tax effects of temporary differences that gave rise to
significant portions of the deferred tax assets and liabilities
at December 31, 2008 and 2007 are presented below:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
74
|
|
|
$
|
92
|
|
Fair value of financial instruments
|
|
|
|
|
|
|
167
|
|
Asset retirement obligations
|
|
|
442
|
|
|
|
387
|
|
Pension benefit obligations
|
|
|
172
|
|
|
|
93
|
|
Other
|
|
|
90
|
|
|
|
123
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
778
|
|
|
|
862
|
|
Valuation allowance
|
|
|
(61
|
)
|
|
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
717
|
|
|
|
812
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property and equipment, principally due to nontaxable business
combinations, differences in depreciation, and the expensing of
intangible drilling costs for tax purposes
|
|
|
(4,229
|
)
|
|
|
(6,152
|
)
|
Fair value of financial instruments
|
|
|
(132
|
)
|
|
|
|
|
Chevron Corporation common stock
|
|
|
|
|
|
|
(431
|
)
|
Long-term debt
|
|
|
(69
|
)
|
|
|
(216
|
)
|
Other
|
|
|
|
|
|
|
(11
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(4,430
|
)
|
|
|
(6,810
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(3,713
|
)
|
|
$
|
(5,998
|
)
|
|
|
|
|
|
|
|
|
|
As shown in the above table, Devon has recognized
$717 million of deferred tax assets as of December 31,
2008, net of a $61 million valuation allowance. Included in
total deferred tax assets is $74 million related to various
carryforwards available to offset future income taxes. The
carryforwards include state net operating loss carryforwards,
which expire primarily between 2009 and 2022, Canadian net
operating loss carryforwards, which expire primarily between
2025 and 2027, and Brazilian net operating loss carryforwards,
which have no expiration. The tax benefits of carryforwards are
recorded as an asset to the extent that management assesses the
utilization of such carryforwards to be more likely than
not. When the future utilization of some portion of the
carryforwards is determined not to be more likely than
not, a valuation allowance is provided to reduce the
recorded tax benefits from such assets.
Devon expects the tax benefits from the state and Canadian net
operating loss carryforwards to be utilized between 2009 and
2013. Such expectation is based upon current estimates of
taxable income during this period, considering limitations on
the annual utilization of these benefits as set forth by tax
regulations. Significant changes in such estimates caused by
variables such as future oil and gas prices or capital
expenditures could alter the timing of the eventual utilization
of such carryforwards. There can be no assurance that Devon will
generate any specific level of continuing taxable earnings.
However, management believes that Devons future taxable
income will more likely than not be sufficient to utilize
substantially all its state and Canadian tax carryforwards prior
to their expiration.
Included in deferred tax assets for net operating loss
carryforwards as of December 31, 2008 and 2007 is
$61 million and $64 million, respectively, related to
the Brazil carryforward. Although this carryforward has no
expiration, management is uncertain whether Devons future
taxable income will be sufficient to utilize its
118
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Brazil carryforward. This uncertainty is based upon annual
limitations on the amount of net operating loss carryforwards
available to reduce taxable income, Devons lack of
historical taxable income in Brazil and the exploratory nature
of several of Devons current projects in Brazil.
Therefore, as of December 31, 2008 and 2007, Devon had a
valuation allowance of $61 million and $50 million,
respectively, related to this carryforward.
Unrecognized
Tax Benefits
The following table presents changes in Devons
unrecognized tax benefits for the year ended December 31,
2008 (in millions).
|
|
|
|
|
Balance as of December 31, 2007
|
|
$
|
111
|
|
Increases (decreases) due to:
|
|
|
|
|
Tax positions taken in current year
|
|
|
159
|
|
Accrual of interest related to tax positions taken
|
|
|
16
|
|
Lapse of statute of limitations
|
|
|
(11
|
)
|
Settlements
|
|
|
(8
|
)
|
Foreign currency translation
|
|
|
(7
|
)
|
|
|
|
|
|
Balance as of December 31, 2008
|
|
$
|
260
|
|
|
|
|
|
|
Devons unrecognized tax benefit balance at
December 31, 2008 and 2007 included $29 million and
$14 million of interest and penalties, respectively.
Included in Devons unrecognized tax benefits of
$260 million as of December 31, 2008 was
$232 million that, if recognized, would affect Devons
effective income tax rate.
Included below is a summary of the tax years, by jurisdiction,
that remain subject to examination by taxing authorities.
|
|
|
|
|
Jurisdiction
|
|
Tax Years Open
|
|
|
U.S. federal
|
|
|
2003-2008
|
|
Various U.S. states
|
|
|
2003-2008
|
|
Canada federal
|
|
|
2001-2008
|
|
Various Canadian provinces
|
|
|
2001-2008
|
|
Various other foreign jurisdictions
|
|
|
2003-2008
|
|
Certain statute of limitation expirations are scheduled to occur
in the next twelve months. However, Devon is currently in
various stages of the administrative review process for certain
open tax years. In addition, Devon is currently subject to
various income tax audits that have not reached the
administrative review process. As a result, Devon cannot
reasonably anticipate the extent that the liabilities for
unrecognized tax benefits will increase or decrease within the
next twelve months.
|
|
16.
|
Discontinued
Operations
|
Egypt
and West Africa
In November 2006 and January 2007, Devon announced its plans to
divest its operations in Egypt and West Africa, including
Equatorial Guinea, Cote dIvoire, Gabon and other countries
in the region.
In October 2007, Devon completed the sale of its Egyptian
operations and received proceeds of $341 million. As a
result of this sale, Devon recognized a $90 million
after-tax gain in the fourth quarter of 2007.
119
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In the second quarter of 2008, Devon sold its assets and
terminated its operations in certain West African countries,
consisting primarily of Equatorial Guinea and Gabon. As a result
of the sales, Devon recognized gains totaling $736 million
($674 million after income taxes) in 2008 from proceeds of
$2.4 billion ($1.7 billion net of income taxes and
purchase price adjustments).
In the third quarter of 2008, Devon sold its assets and
terminated its operations in Cote dIvoire. As a result of
this sale, Devon recognized a gain of $83 million
($95 million after income taxes) in 2008 from proceeds of
$205 million ($163 million net of income taxes and
purchase price adjustments).
With the Cote dIvoire transaction, Devon completed the
divestitures of all its oil and gas producing properties in
Africa. The Africa divestitures generated just over
$3.0 billion of sales proceeds. After income taxes and
purchase price adjustments, such proceeds totaled
$2.2 billion and generated after-tax gains of
$0.8 billion.
Revenues related to Devons operations in Egypt and West
Africa totaled $349 million, $781 million and
$929 million during 2008, 2007 and 2006, respectively. The
following table presents the main classes of assets and
liabilities associated with Devons operations in Egypt and
West Africa as of December 31, 2008 and 2007. As of
December 31, 2008, the remaining assets and liabilities
primarily are associated with nonproducing oil and gas
properties in Angola and Nigeria.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
5
|
|
|
$
|
9
|
|
Accounts receivable
|
|
|
|
|
|
|
83
|
|
Other current assets
|
|
|
22
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
27
|
|
|
$
|
120
|
|
|
|
|
|
|
|
|
|
|
Long-term assets property and equipment, net of
accumulated depreciation, depletion and amortization
|
|
$
|
19
|
|
|
$
|
1,512
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable trade
|
|
$
|
7
|
|
|
$
|
23
|
|
Revenues and royalties due to others
|
|
|
|
|
|
|
11
|
|
Income taxes payable
|
|
|
|
|
|
|
100
|
|
Current portion of asset retirement obligations
|
|
|
|
|
|
|
9
|
|
Accrued expenses and other current liabilities
|
|
|
6
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
13
|
|
|
$
|
145
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, long-term
|
|
$
|
|
|
|
$
|
35
|
|
Deferred income taxes
|
|
|
|
|
|
|
366
|
|
Other liabilities
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities
|
|
$
|
|
|
|
$
|
404
|
|
|
|
|
|
|
|
|
|
|
Reductions
of carrying value related to discontinued
operations
Based on drilling activities in Nigeria, Devon reduced the
carrying value of its Nigerian assets held for sale in 2008 and
2007. As a result, earnings from discontinued operations include
after-tax losses of $6 million ($6 million pre-tax)
and $13 million ($64 million pre-tax) in 2008 and
2007, respectively.
120
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
As a result of unsuccessful exploratory activities in Egypt
during 2006, the net book value of Devons Egyptian oil and
gas properties, less related deferred income taxes, exceeded the
ceiling by $18 million as of the end of September 30,
2006. Therefore, in 2006, Devon recognized an $18 million
after-tax loss ($31 million pre-tax).
Due to unsuccessful drilling activities in Nigeria, in the first
quarter of 2006, Devon recognized an $85 million impairment
of its investment in Nigeria equal to the costs to drill two dry
holes and a proportionate share of block-related costs. There
was no income tax benefit related to this impairment.
|
|
17.
|
(Loss)
Earnings Per Share
|
The following table reconciles earnings from continuing
operations and common shares outstanding used in the
calculations of basic and diluted (loss) earnings per share for
2008, 2007 and 2006. The 2008 diluted per share calculations
include an increase of four million common shares outstanding
due to dilutive shares. However, because a net loss from
continuing operations was generated during 2008, the dilutive
shares produce an antidilutive net loss per share result.
Therefore, the diluted loss per share from continuing operations
reported in the accompanying 2008 statement of operations
is the same as the basic loss per share amount.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (Loss)
|
|
|
|
|
|
|
|
|
|
Earnings
|
|
|
Weighted
|
|
|
|
|
|
|
Applicable to
|
|
|
Average
|
|
|
Net (Loss)
|
|
|
|
Common
|
|
|
Common Shares
|
|
|
Earnings
|
|
|
|
Stockholders
|
|
|
Outstanding
|
|
|
per Share
|
|
|
|
(In millions, except per share amounts)
|
|
|
Year Ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
|
|
$
|
(3,079
|
)
|
|
|
|
|
|
|
|
|
Less preferred stock dividends
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted loss per share
|
|
$
|
(3,084
|
)
|
|
|
444
|
|
|
$
|
(6.95
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations
|
|
$
|
3,146
|
|
|
|
|
|
|
|
|
|
Less preferred stock dividends
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share
|
|
|
3,136
|
|
|
|
445
|
|
|
$
|
7.05
|
|
Dilutive effect of potential common shares issuable upon the
exercise of outstanding stock options
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share
|
|
$
|
3,136
|
|
|
|
450
|
|
|
$
|
6.97
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations
|
|
$
|
2,634
|
|
|
|
|
|
|
|
|
|
Less preferred stock dividends
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share
|
|
|
2,624
|
|
|
|
442
|
|
|
$
|
5.94
|
|
Dilutive effect of potential common shares issuable upon the
exercise of outstanding stock options
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share
|
|
$
|
2,624
|
|
|
|
448
|
|
|
$
|
5.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Certain options to purchase shares of Devons common stock
were excluded from the dilution calculations because the options
were antidilutive. These excluded options totaled 2 million
and 3 million in 2007 and 2006, respectively.
121
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Devon manages its business by country. As such, Devon identifies
its segments based on geographic areas. Devon has three
reportable segments: its operations in the U.S., its operations
in Canada, and its international operations outside of North
America. Substantially all of these segments operations
involve oil and gas producing activities. Certain information
regarding such activities for each segment is included in
Note 20.
Following is certain financial information regarding
Devons segments for 2008, 2007 and 2006. The revenues
reported are all from external customers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Canada
|
|
|
International
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
As of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
1,925
|
|
|
$
|
367
|
|
|
$
|
392
|
|
|
$
|
2,684
|
|
Property and equipment, net of accumulated depreciation,
depletion and amortization
|
|
|
17,676
|
|
|
|
4,355
|
|
|
|
943
|
|
|
|
22,974
|
|
Goodwill
|
|
|
3,046
|
|
|
|
2,465
|
|
|
|
68
|
|
|
|
5,579
|
|
Other assets
|
|
|
360
|
|
|
|
72
|
|
|
|
239
|
|
|
|
671
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
23,007
|
|
|
$
|
7,259
|
|
|
$
|
1,642
|
|
|
$
|
31,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
2,227
|
|
|
$
|
543
|
|
|
$
|
365
|
|
|
$
|
3,135
|
|
Long-term debt
|
|
|
2,683
|
|
|
|
2,978
|
|
|
|
|
|
|
|
5,661
|
|
Asset retirement obligations, long-term
|
|
|
694
|
|
|
|
555
|
|
|
|
98
|
|
|
|
1,347
|
|
Other liabilities
|
|
|
983
|
|
|
|
40
|
|
|
|
3
|
|
|
|
1,026
|
|
Deferred income taxes
|
|
|
2,734
|
|
|
|
880
|
|
|
|
65
|
|
|
|
3,679
|
|
Stockholders equity
|
|
|
13,686
|
|
|
|
2,263
|
|
|
|
1,111
|
|
|
|
17,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
23,007
|
|
|
$
|
7,259
|
|
|
$
|
1,642
|
|
|
$
|
31,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
122
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Canada
|
|
|
International
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Year Ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
1,698
|
|
|
$
|
1,535
|
|
|
$
|
1,334
|
|
|
$
|
4,567
|
|
Gas sales
|
|
|
5,511
|
|
|
|
1,733
|
|
|
|
19
|
|
|
|
7,263
|
|
NGL sales
|
|
|
997
|
|
|
|
246
|
|
|
|
|
|
|
|
1,243
|
|
Net loss on oil and gas derivative financial instruments
|
|
|
(154
|
)
|
|
|
|
|
|
|
|
|
|
|
(154
|
)
|
Marketing and midstream revenues
|
|
|
2,247
|
|
|
|
45
|
|
|
|
|
|
|
|
2,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
10,299
|
|
|
|
3,559
|
|
|
|
1,353
|
|
|
|
15,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
1,193
|
|
|
|
809
|
|
|
|
215
|
|
|
|
2,217
|
|
Production taxes
|
|
|
302
|
|
|
|
4
|
|
|
|
216
|
|
|
|
522
|
|
Marketing and midstream operating costs and expenses
|
|
|
1,606
|
|
|
|
18
|
|
|
|
|
|
|
|
1,624
|
|
Depreciation, depletion and amortization of oil and gas
properties
|
|
|
1,998
|
|
|
|
950
|
|
|
|
305
|
|
|
|
3,253
|
|
Depreciation and amortization of non-oil and gas properties
|
|
|
229
|
|
|
|
26
|
|
|
|
1
|
|
|
|
256
|
|
Accretion of asset retirement obligations
|
|
|
42
|
|
|
|
38
|
|
|
|
6
|
|
|
|
86
|
|
General and administrative expenses
|
|
|
518
|
|
|
|
133
|
|
|
|
2
|
|
|
|
653
|
|
Interest expense
|
|
|
117
|
|
|
|
212
|
|
|
|
|
|
|
|
329
|
|
Change in fair value of other financial instruments
|
|
|
149
|
|
|
|
|
|
|
|
|
|
|
|
149
|
|
Reduction of carrying value of oil and gas properties
|
|
|
6,538
|
|
|
|
3,353
|
|
|
|
488
|
|
|
|
10,379
|
|
Other income, net
|
|
|
(203
|
)
|
|
|
(14
|
)
|
|
|
(7
|
)
|
|
|
(224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net
|
|
|
12,489
|
|
|
|
5,529
|
|
|
|
1,226
|
|
|
|
19,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations before income taxes
|
|
|
(2,190
|
)
|
|
|
(1,970
|
)
|
|
|
127
|
|
|
|
(4,033
|
)
|
Income tax (benefit) expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
289
|
|
|
|
152
|
|
|
|
178
|
|
|
|
619
|
|
Deferred
|
|
|
(940
|
)
|
|
|
(622
|
)
|
|
|
(11
|
)
|
|
|
(1,573
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax (benefit) expense
|
|
|
(651
|
)
|
|
|
(470
|
)
|
|
|
167
|
|
|
|
(954
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
|
|
|
(1,539
|
)
|
|
|
(1,500
|
)
|
|
|
(40
|
)
|
|
|
(3,079
|
)
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income taxes
|
|
|
|
|
|
|
|
|
|
|
1,131
|
|
|
|
1,131
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
200
|
|
|
|
200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
931
|
|
|
|
931
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
|
(1,539
|
)
|
|
|
(1,500
|
)
|
|
|
891
|
|
|
|
(2,148
|
)
|
Preferred stock dividends
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings applicable to common stockholders
|
|
$
|
(1,544
|
)
|
|
$
|
(1,500
|
)
|
|
$
|
891
|
|
|
$
|
(2,153
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset retirement
obligations
|
|
$
|
8,313
|
|
|
$
|
1,639
|
|
|
$
|
558
|
|
|
$
|
10,510
|
|
Revision of future asset retirement obligations
|
|
|
152
|
|
|
|
73
|
|
|
|
19
|
|
|
|
244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations
|
|
$
|
8,465
|
|
|
$
|
1,712
|
|
|
$
|
577
|
|
|
$
|
10,754
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
123
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Canada
|
|
|
International
|
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
As of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
1,601
|
|
|
$
|
852
|
|
|
$
|
1,461
|
|
|
$
|
3,914
|
|
Property and equipment, net of accumulated depreciation,
depletion and amortization
|
|
|
18,019
|
|
|
|
8,909
|
|
|
|
1,151
|
|
|
|
28,079
|
|
Goodwill
|
|
|
3,049
|
|
|
|
3,055
|
|
|
|
68
|
|
|
|
6,172
|
|
Other assets
|
|
|
1,651
|
|
|
|
49
|
|
|
|
1,591
|
|
|
|
3,291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
24,320
|
|
|
$
|
12,865
|
|
|
$
|
4,271
|
|
|
$
|
41,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
2,661
|
|
|
$
|
561
|
|
|
$
|
435
|
|
|
$
|
3,657
|
|
Long-term debt
|
|
|
3,948
|
|
|
|
2,976
|
|
|
|
|
|
|
|
6,924
|
|
Asset retirement obligations, long-term
|
|
|
594
|
|
|
|
569
|
|
|
|
73
|
|
|
|
1,236
|
|
Other liabilities
|
|
|
1,137
|
|
|
|
45
|
|
|
|
409
|
|
|
|
1,591
|
|
Deferred income taxes
|
|
|
3,980
|
|
|
|
2,011
|
|
|
|
51
|
|
|
|
6,042
|
|
Stockholders equity
|
|
|
12,000
|
|
|
|
6,703
|
|
|
|
3,303
|
|
|
|
22,006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
24,320
|
|
|
$
|
12,865
|
|
|
$
|
4,271
|
|
|
$
|
41,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
124
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Canada
|
|
|
International
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
1,313
|
|
|
$
|
804
|
|
|
$
|
1,376
|
|
|
$
|
3,493
|
|
Gas sales
|
|
|
3,728
|
|
|
|
1,410
|
|
|
|
11
|
|
|
|
5,149
|
|
NGL sales
|
|
|
773
|
|
|
|
197
|
|
|
|
|
|
|
|
970
|
|
Net gain on oil and gas derivative financial instruments
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Marketing and midstream revenues
|
|
|
1,693
|
|
|
|
43
|
|
|
|
|
|
|
|
1,736
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
7,521
|
|
|
|
2,454
|
|
|
|
1,387
|
|
|
|
11,362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
1,005
|
|
|
|
654
|
|
|
|
169
|
|
|
|
1,828
|
|
Production taxes
|
|
|
212
|
|
|
|
4
|
|
|
|
124
|
|
|
|
340
|
|
Marketing and midstream operating costs and expenses
|
|
|
1,211
|
|
|
|
16
|
|
|
|
|
|
|
|
1,227
|
|
Depreciation, depletion and amortization of oil and gas
properties
|
|
|
1,672
|
|
|
|
740
|
|
|
|
243
|
|
|
|
2,655
|
|
Depreciation and amortization of non-oil and gas properties
|
|
|
180
|
|
|
|
21
|
|
|
|
2
|
|
|
|
203
|
|
Accretion of asset retirement obligations
|
|
|
38
|
|
|
|
32
|
|
|
|
4
|
|
|
|
74
|
|
General and administrative expenses
|
|
|
399
|
|
|
|
119
|
|
|
|
(5
|
)
|
|
|
513
|
|
Interest expense
|
|
|
228
|
|
|
|
202
|
|
|
|
|
|
|
|
430
|
|
Change in fair value of other financial instruments
|
|
|
(32
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
(34
|
)
|
Other income, net
|
|
|
(34
|
)
|
|
|
(17
|
)
|
|
|
(47
|
)
|
|
|
(98
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net
|
|
|
4,879
|
|
|
|
1,769
|
|
|
|
490
|
|
|
|
7,138
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes
|
|
|
2,642
|
|
|
|
685
|
|
|
|
897
|
|
|
|
4,224
|
|
Income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
100
|
|
|
|
135
|
|
|
|
265
|
|
|
|
500
|
|
Deferred
|
|
|
773
|
|
|
|
(166
|
)
|
|
|
(29
|
)
|
|
|
578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit)
|
|
|
873
|
|
|
|
(31
|
)
|
|
|
236
|
|
|
|
1,078
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations
|
|
|
1,769
|
|
|
|
716
|
|
|
|
661
|
|
|
|
3,146
|
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income taxes
|
|
|
|
|
|
|
|
|
|
|
696
|
|
|
|
696
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
236
|
|
|
|
236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
460
|
|
|
|
460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
|
1,769
|
|
|
|
716
|
|
|
|
1,121
|
|
|
|
3,606
|
|
Preferred stock dividends
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders
|
|
$
|
1,759
|
|
|
$
|
716
|
|
|
$
|
1,121
|
|
|
$
|
3,596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset retirement
obligations
|
|
$
|
4,522
|
|
|
$
|
1,350
|
|
|
$
|
455
|
|
|
$
|
6,327
|
|
Revision of future asset retirement obligations
|
|
|
210
|
|
|
|
99
|
|
|
|
2
|
|
|
|
311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations
|
|
$
|
4,732
|
|
|
$
|
1,449
|
|
|
$
|
457
|
|
|
$
|
6,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
125
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Canada
|
|
|
International
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Year Ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
1,218
|
|
|
$
|
603
|
|
|
$
|
613
|
|
|
$
|
2,434
|
|
Gas sales
|
|
|
3,407
|
|
|
|
1,456
|
|
|
|
11
|
|
|
|
4,874
|
|
NGL sales
|
|
|
548
|
|
|
|
201
|
|
|
|
|
|
|
|
749
|
|
Net gain on oil and gas derivative financial instruments
|
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
38
|
|
Marketing and midstream revenues
|
|
|
1,641
|
|
|
|
31
|
|
|
|
|
|
|
|
1,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
6,852
|
|
|
|
2,291
|
|
|
|
624
|
|
|
|
9,767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
813
|
|
|
|
543
|
|
|
|
69
|
|
|
|
1,425
|
|
Production taxes
|
|
|
235
|
|
|
|
7
|
|
|
|
99
|
|
|
|
341
|
|
Marketing and midstream operating costs and expenses
|
|
|
1,226
|
|
|
|
10
|
|
|
|
|
|
|
|
1,236
|
|
Depreciation, depletion and amortization of oil and gas
properties
|
|
|
1,311
|
|
|
|
644
|
|
|
|
103
|
|
|
|
2,058
|
|
Depreciation and amortization of non-oil and gas properties
|
|
|
154
|
|
|
|
18
|
|
|
|
1
|
|
|
|
173
|
|
Accretion of asset retirement obligations
|
|
|
25
|
|
|
|
21
|
|
|
|
1
|
|
|
|
47
|
|
General and administrative expenses
|
|
|
316
|
|
|
|
92
|
|
|
|
(11
|
)
|
|
|
397
|
|
Interest expense
|
|
|
199
|
|
|
|
222
|
|
|
|
|
|
|
|
421
|
|
Change in fair value of other financial instruments
|
|
|
181
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
178
|
|
Reduction of carrying value of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
36
|
|
Other income, net
|
|
|
(43
|
)
|
|
|
(14
|
)
|
|
|
(58
|
)
|
|
|
(115
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net
|
|
|
4,417
|
|
|
|
1,540
|
|
|
|
240
|
|
|
|
6,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes
|
|
|
2,435
|
|
|
|
751
|
|
|
|
384
|
|
|
|
3,570
|
|
Income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
299
|
|
|
|
143
|
|
|
|
86
|
|
|
|
528
|
|
Deferred
|
|
|
533
|
|
|
|
(105
|
)
|
|
|
(20
|
)
|
|
|
408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense
|
|
|
832
|
|
|
|
38
|
|
|
|
66
|
|
|
|
936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations
|
|
|
1,603
|
|
|
|
713
|
|
|
|
318
|
|
|
|
2,634
|
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income taxes
|
|
|
|
|
|
|
|
|
|
|
464
|
|
|
|
464
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
252
|
|
|
|
252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
212
|
|
|
|
212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
|
1,603
|
|
|
|
713
|
|
|
|
530
|
|
|
|
2,846
|
|
Preferred stock dividends
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders
|
|
$
|
1,593
|
|
|
$
|
713
|
|
|
$
|
530
|
|
|
$
|
2,836
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset retirement
obligations
|
|
$
|
5,814
|
|
|
$
|
1,670
|
|
|
$
|
405
|
|
|
$
|
7,889
|
|
Revision of future asset retirement obligations
|
|
|
63
|
|
|
|
71
|
|
|
|
1
|
|
|
|
135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations
|
|
$
|
5,877
|
|
|
$
|
1,741
|
|
|
$
|
406
|
|
|
$
|
8,024
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
126
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
19.
|
Supplemental
Information to Statements of Cash Flows
|
Additional information related to Devons 2008, 2007 and
2006 statements of cash flows are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Net increase in working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease (increase) in accounts receivable
|
|
$
|
291
|
|
|
$
|
(329
|
)
|
|
$
|
91
|
|
Increase in other current assets
|
|
|
(78
|
)
|
|
|
(38
|
)
|
|
|
(33
|
)
|
Increase in accounts payable
|
|
|
155
|
|
|
|
43
|
|
|
|
168
|
|
Increase (decrease) in revenues and royalties due to others
|
|
|
15
|
|
|
|
76
|
|
|
|
(343
|
)
|
Decrease in income taxes payable
|
|
|
(349
|
)
|
|
|
(28
|
)
|
|
|
(245
|
)
|
(Decrease) increase in other current liabilities
|
|
|
(172
|
)
|
|
|
(223
|
)
|
|
|
80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in working capital
|
|
$
|
(138
|
)
|
|
$
|
(499
|
)
|
|
$
|
(282
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary cash flow data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid (net of capitalized interest)
|
|
$
|
336
|
|
|
$
|
406
|
|
|
$
|
384
|
|
Income taxes paid (continuing and discontinued operations)
|
|
$
|
1,436
|
|
|
$
|
588
|
|
|
$
|
960
|
|
Noncash investing activity exchange of investment in
Chevron common stock for oil and gas properties (see Note 6)
|
|
$
|
610
|
|
|
$
|
|
|
|
$
|
|
|
|
|
20.
|
Supplemental
Information on Oil and Gas Operations (Unaudited)
|
The following supplemental unaudited information regarding the
oil and gas activities of Devon is presented pursuant to the
disclosure requirements promulgated by the Securities and
Exchange Commission and SFAS No. 69, Disclosures
About Oil and Gas Producing Activities. This supplemental
information excludes amounts for all periods presented related
to Devons discontinued operations in Egypt and West Africa.
Costs
Incurred
The following tables reflect the costs incurred in oil and gas
property acquisition, exploration, and development activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
822
|
|
|
$
|
10
|
|
|
$
|
1,113
|
|
Unproved properties
|
|
|
1,764
|
|
|
|
206
|
|
|
|
1,481
|
|
Exploration costs
|
|
|
1,342
|
|
|
|
891
|
|
|
|
881
|
|
Development costs
|
|
|
6,122
|
|
|
|
4,994
|
|
|
|
4,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred
|
|
$
|
10,050
|
|
|
$
|
6,101
|
|
|
$
|
7,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
127
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
822
|
|
|
$
|
3
|
|
|
$
|
1,066
|
|
Unproved properties
|
|
|
1,411
|
|
|
|
156
|
|
|
|
1,366
|
|
Exploration costs
|
|
|
844
|
|
|
|
569
|
|
|
|
547
|
|
Development costs
|
|
|
4,733
|
|
|
|
3,542
|
|
|
|
2,558
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred
|
|
$
|
7,810
|
|
|
$
|
4,270
|
|
|
$
|
5,537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
|
|
|
$
|
7
|
|
|
$
|
23
|
|
Unproved properties
|
|
|
352
|
|
|
|
49
|
|
|
|
70
|
|
Exploration costs
|
|
|
173
|
|
|
|
211
|
|
|
|
217
|
|
Development costs
|
|
|
1,131
|
|
|
|
1,098
|
|
|
|
1,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred
|
|
$
|
1,656
|
|
|
$
|
1,365
|
|
|
$
|
1,554
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
|
|
|
$
|
|
|
|
$
|
24
|
|
Unproved properties
|
|
|
1
|
|
|
|
1
|
|
|
|
45
|
|
Exploration costs
|
|
|
325
|
|
|
|
111
|
|
|
|
117
|
|
Development costs
|
|
|
258
|
|
|
|
354
|
|
|
|
233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred
|
|
$
|
584
|
|
|
$
|
466
|
|
|
$
|
419
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pursuant to the full cost method of accounting, Devon
capitalizes certain of its general and administrative expenses
that are related to property acquisition, exploration and
development activities. Such capitalized expenses, which are
included in the costs shown in the preceding tables, were
$406 million, $312 million and $243 million in
the years 2008, 2007 and 2006, respectively. Also, Devon
capitalizes interest costs incurred and attributable to unproved
oil and gas properties and major development projects of oil and
gas properties. Capitalized interest expenses, which are
included in the costs shown in the preceding tables, were
$96 million, $65 million and $49 million in the
years 2008, 2007 and 2006, respectively.
Results
of Operations for Oil and Gas Producing Activities
The following tables include revenues and expenses associated
directly with Devons continuing oil and gas producing
activities, including general and administrative expenses
directly related to such producing activities. They do not
include any allocation of Devons interest costs or general
corporate overhead and, therefore, are not necessarily
indicative of the contribution to net earnings of Devons
oil and gas operations.
128
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Income tax expense has been calculated by applying statutory
income tax rates to oil, gas and NGL sales after deducting
costs, including depreciation, depletion and amortization and
after giving effect to permanent differences.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions, except per equivalent barrel amounts)
|
|
|
Oil, gas and NGL sales
|
|
$
|
13,073
|
|
|
$
|
9,612
|
|
|
$
|
8,057
|
|
Production and operating expenses
|
|
|
(2,739
|
)
|
|
|
(2,168
|
)
|
|
|
(1,766
|
)
|
Depreciation, depletion and amortization
|
|
|
(3,253
|
)
|
|
|
(2,655
|
)
|
|
|
(2,058
|
)
|
Accretion of asset retirement obligations
|
|
|
(86
|
)
|
|
|
(74
|
)
|
|
|
(47
|
)
|
General and administrative expenses
|
|
|
(199
|
)
|
|
|
(202
|
)
|
|
|
(134
|
)
|
Reduction of carrying value of oil and gas properties
|
|
|
(10,379
|
)
|
|
|
|
|
|
|
(36
|
)
|
Income tax benefit (expense)
|
|
|
950
|
|
|
|
(1,257
|
)
|
|
|
(1,185
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
(2,633
|
)
|
|
$
|
3,256
|
|
|
$
|
2,831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization per Boe
|
|
$
|
13.68
|
|
|
$
|
11.85
|
|
|
$
|
10.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions, except per equivalent barrel amounts)
|
|
|
Oil, gas and NGL sales
|
|
$
|
8,206
|
|
|
$
|
5,814
|
|
|
$
|
5,173
|
|
Production and operating expenses
|
|
|
(1,495
|
)
|
|
|
(1,217
|
)
|
|
|
(1,048
|
)
|
Depreciation, depletion and amortization
|
|
|
(1,998
|
)
|
|
|
(1,672
|
)
|
|
|
(1,311
|
)
|
Accretion of asset retirement obligations
|
|
|
(42
|
)
|
|
|
(38
|
)
|
|
|
(25
|
)
|
General and administrative expenses
|
|
|
(148
|
)
|
|
|
(143
|
)
|
|
|
(94
|
)
|
Reduction of carrying value of oil and gas properties
|
|
|
(6,538
|
)
|
|
|
|
|
|
|
|
|
Income tax benefit (expense)
|
|
|
719
|
|
|
|
(966
|
)
|
|
|
(990
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
(1,296
|
)
|
|
$
|
1,778
|
|
|
$
|
1,705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization per Boe
|
|
$
|
12.31
|
|
|
$
|
11.44
|
|
|
$
|
9.89
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions, except per equivalent barrel amounts)
|
|
|
Oil, gas and NGL sales
|
|
$
|
3,514
|
|
|
$
|
2,411
|
|
|
$
|
2,260
|
|
Production and operating expenses
|
|
|
(813
|
)
|
|
|
(658
|
)
|
|
|
(550
|
)
|
Depreciation, depletion and amortization
|
|
|
(950
|
)
|
|
|
(740
|
)
|
|
|
(644
|
)
|
Accretion of asset retirement obligations
|
|
|
(38
|
)
|
|
|
(32
|
)
|
|
|
(21
|
)
|
General and administrative expenses
|
|
|
(37
|
)
|
|
|
(36
|
)
|
|
|
(29
|
)
|
Reduction of carrying value of oil and gas properties
|
|
|
(3,353
|
)
|
|
|
|
|
|
|
|
|
Income tax benefit (expense)
|
|
|
391
|
|
|
|
(63
|
)
|
|
|
(144
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
(1,286
|
)
|
|
$
|
882
|
|
|
$
|
872
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization per Boe
|
|
$
|
15.59
|
|
|
$
|
12.73
|
|
|
$
|
11.17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
129
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions, except per equivalent barrel amounts)
|
|
|
Oil, gas and NGL sales
|
|
$
|
1,353
|
|
|
$
|
1,387
|
|
|
$
|
624
|
|
Production and operating expenses
|
|
|
(431
|
)
|
|
|
(293
|
)
|
|
|
(168
|
)
|
Depreciation, depletion and amortization
|
|
|
(305
|
)
|
|
|
(243
|
)
|
|
|
(103
|
)
|
Accretion of asset retirement obligations
|
|
|
(6
|
)
|
|
|
(4
|
)
|
|
|
(1
|
)
|
General and administrative expenses
|
|
|
(14
|
)
|
|
|
(23
|
)
|
|
|
(11
|
)
|
Reduction of carrying value of oil and gas properties
|
|
|
(488
|
)
|
|
|
|
|
|
|
(36
|
)
|
Income tax expense
|
|
|
(160
|
)
|
|
|
(228
|
)
|
|
|
(51
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
(51
|
)
|
|
$
|
596
|
|
|
$
|
254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization per Boe
|
|
$
|
20.94
|
|
|
$
|
12.31
|
|
|
$
|
10.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In 2008, 2007 and 2006, the total and Canadian income tax
amounts in the tables above were reduced by $7 million,
$261 million and $243 million, respectively, due to
statutory rate reductions that were enacted in each such year.
Quantities
of Oil and Gas Reserves
Set forth below is a summary of the reserves that were
evaluated, either by preparation or audit, by independent
petroleum consultants for each of the years ended 2008, 2007 and
2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Prepared
|
|
|
Audited
|
|
|
Prepared
|
|
|
Audited
|
|
|
Prepared
|
|
|
Audited
|
|
|
Domestic
|
|
|
5
|
%
|
|
|
87
|
%
|
|
|
6
|
%
|
|
|
83
|
%
|
|
|
7
|
%
|
|
|
81
|
%
|
Canada
|
|
|
|
|
|
|
78
|
%
|
|
|
34
|
%
|
|
|
51
|
%
|
|
|
46
|
%
|
|
|
39
|
%
|
International
|
|
|
99
|
%
|
|
|
|
|
|
|
99
|
%
|
|
|
|
|
|
|
99
|
%
|
|
|
|
|
Total
|
|
|
9
|
%
|
|
|
81
|
%
|
|
|
19
|
%
|
|
|
69
|
%
|
|
|
28
|
%
|
|
|
61
|
%
|
Prepared reserves are those quantities of reserves
that were prepared by an independent petroleum consultant.
Audited reserves are those quantities of reserves
that were estimated by Devon employees and audited by an
independent petroleum consultant. An audit is an examination of
a companys proved oil and gas reserves and net cash flow
by an independent petroleum consultant that is conducted for the
purpose of expressing an opinion as to whether such estimates,
in aggregate, are reasonable and have been estimated and
presented in conformity with generally accepted petroleum
engineering and evaluation principles.
The domestic reserves were evaluated by the independent
petroleum consultants of LaRoche Petroleum Consultants, Ltd. and
Ryder Scott Company, L.P. in each of the years presented. The
Canadian reserves were evaluated by the independent petroleum
consultants of AJM Petroleum Consultants in each of the years
presented. The International reserves were evaluated by the
independent petroleum consultants of Ryder Scott Company, L.P.
in each of the years presented.
130
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Set forth below is a summary of the changes in the net
quantities of crude oil, gas and natural gas liquids reserves
for each of the three years ended December 31, 2008.
Additional discussion of the significant proved reserve changes
follows the tables below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Liquids
|
|
|
Total
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBoe)
|
|
|
Proved reserves as of December 31, 2005
|
|
|
555
|
|
|
|
7,192
|
|
|
|
246
|
|
|
|
2,000
|
|
Revisions due to prices
|
|
|
(22
|
)
|
|
|
(87
|
)
|
|
|
(7
|
)
|
|
|
(44
|
)
|
Revisions other than price
|
|
|
4
|
|
|
|
(107
|
)
|
|
|
5
|
|
|
|
(8
|
)
|
Extensions and discoveries
|
|
|
139
|
|
|
|
1,490
|
|
|
|
45
|
|
|
|
433
|
|
Purchase of reserves
|
|
|
|
|
|
|
584
|
|
|
|
9
|
|
|
|
106
|
|
Production
|
|
|
(42
|
)
|
|
|
(808
|
)
|
|
|
(23
|
)
|
|
|
(200
|
)
|
Sale of reserves
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2006
|
|
|
634
|
|
|
|
8,259
|
|
|
|
275
|
|
|
|
2,286
|
|
Revisions due to prices
|
|
|
11
|
|
|
|
169
|
|
|
|
5
|
|
|
|
44
|
|
Revisions other than price
|
|
|
31
|
|
|
|
155
|
|
|
|
20
|
|
|
|
75
|
|
Extensions and discoveries
|
|
|
56
|
|
|
|
1,272
|
|
|
|
47
|
|
|
|
315
|
|
Purchase of reserves
|
|
|
1
|
|
|
|
15
|
|
|
|
|
|
|
|
3
|
|
Production
|
|
|
(55
|
)
|
|
|
(863
|
)
|
|
|
(26
|
)
|
|
|
(224
|
)
|
Sale of reserves
|
|
|
(1
|
)
|
|
|
(13
|
)
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2007
|
|
|
677
|
|
|
|
8,994
|
|
|
|
321
|
|
|
|
2,496
|
|
Revisions due to prices
|
|
|
(355
|
)
|
|
|
(588
|
)
|
|
|
(20
|
)
|
|
|
(473
|
)
|
Revisions other than price
|
|
|
16
|
|
|
|
95
|
|
|
|
6
|
|
|
|
38
|
|
Extensions and discoveries
|
|
|
132
|
|
|
|
2,077
|
|
|
|
67
|
|
|
|
546
|
|
Purchase of reserves
|
|
|
18
|
|
|
|
252
|
|
|
|
6
|
|
|
|
66
|
|
Production
|
|
|
(53
|
)
|
|
|
(940
|
)
|
|
|
(28
|
)
|
|
|
(238
|
)
|
Sale of reserves
|
|
|
(6
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2008
|
|
|
429
|
|
|
|
9,885
|
|
|
|
352
|
|
|
|
2,428
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
306
|
|
|
|
6,073
|
|
|
|
216
|
|
|
|
1,535
|
|
December 31, 2006
|
|
|
318
|
|
|
|
6,484
|
|
|
|
229
|
|
|
|
1,628
|
|
December 31, 2007
|
|
|
391
|
|
|
|
7,255
|
|
|
|
274
|
|
|
|
1,874
|
|
December 31, 2008
|
|
|
301
|
|
|
|
8,044
|
|
|
|
292
|
|
|
|
1,934
|
|
131
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Liquids
|
|
|
Total
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBoe)
|
|
|
Proved reserves as of December 31, 2005
|
|
|
173
|
|
|
|
5,164
|
|
|
|
197
|
|
|
|
1,232
|
|
Revisions due to prices
|
|
|
|
|
|
|
(110
|
)
|
|
|
(3
|
)
|
|
|
(22
|
)
|
Revisions other than price
|
|
|
|
|
|
|
(11
|
)
|
|
|
6
|
|
|
|
5
|
|
Extensions and discoveries
|
|
|
16
|
|
|
|
1,298
|
|
|
|
43
|
|
|
|
274
|
|
Purchase of reserves
|
|
|
|
|
|
|
580
|
|
|
|
9
|
|
|
|
105
|
|
Production
|
|
|
(19
|
)
|
|
|
(566
|
)
|
|
|
(19
|
)
|
|
|
(132
|
)
|
Sale of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2006
|
|
|
170
|
|
|
|
6,355
|
|
|
|
233
|
|
|
|
1,462
|
|
Revisions due to prices
|
|
|
4
|
|
|
|
119
|
|
|
|
5
|
|
|
|
29
|
|
Revisions other than price
|
|
|
6
|
|
|
|
174
|
|
|
|
21
|
|
|
|
56
|
|
Extensions and discoveries
|
|
|
9
|
|
|
|
1,133
|
|
|
|
45
|
|
|
|
242
|
|
Purchase of reserves
|
|
|
1
|
|
|
|
10
|
|
|
|
|
|
|
|
2
|
|
Production
|
|
|
(19
|
)
|
|
|
(635
|
)
|
|
|
(22
|
)
|
|
|
(146
|
)
|
Sale of reserves
|
|
|
(1
|
)
|
|
|
(13
|
)
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2007
|
|
|
170
|
|
|
|
7,143
|
|
|
|
282
|
|
|
|
1,642
|
|
Revisions due to prices
|
|
|
(20
|
)
|
|
|
(369
|
)
|
|
|
(18
|
)
|
|
|
(100
|
)
|
Revisions other than price
|
|
|
5
|
|
|
|
106
|
|
|
|
6
|
|
|
|
28
|
|
Extensions and discoveries
|
|
|
12
|
|
|
|
1,966
|
|
|
|
65
|
|
|
|
405
|
|
Purchase of reserves
|
|
|
18
|
|
|
|
250
|
|
|
|
6
|
|
|
|
66
|
|
Production
|
|
|
(17
|
)
|
|
|
(726
|
)
|
|
|
(24
|
)
|
|
|
(162
|
)
|
Sale of reserves
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2008
|
|
|
167
|
|
|
|
8,369
|
|
|
|
317
|
|
|
|
1,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
149
|
|
|
|
4,343
|
|
|
|
175
|
|
|
|
1,049
|
|
December 31, 2006
|
|
|
147
|
|
|
|
4,916
|
|
|
|
196
|
|
|
|
1,163
|
|
December 31, 2007
|
|
|
148
|
|
|
|
5,743
|
|
|
|
244
|
|
|
|
1,349
|
|
December 31, 2008
|
|
|
133
|
|
|
|
6,681
|
|
|
|
261
|
|
|
|
1,508
|
|
132
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Liquids
|
|
|
Total
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBoe)
|
|
|
Proved reserves as of December 31, 2005
|
|
|
253
|
|
|
|
2,006
|
|
|
|
49
|
|
|
|
636
|
|
Revisions due to prices
|
|
|
(19
|
)
|
|
|
23
|
|
|
|
(4
|
)
|
|
|
(20
|
)
|
Revisions other than price
|
|
|
(1
|
)
|
|
|
(84
|
)
|
|
|
(1
|
)
|
|
|
(16
|
)
|
Extensions and discoveries
|
|
|
109
|
|
|
|
193
|
|
|
|
2
|
|
|
|
145
|
|
Purchase of reserves
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
1
|
|
Production
|
|
|
(13
|
)
|
|
|
(241
|
)
|
|
|
(4
|
)
|
|
|
(58
|
)
|
Sale of reserves
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2006
|
|
|
329
|
|
|
|
1,896
|
|
|
|
42
|
|
|
|
687
|
|
Revisions due to prices
|
|
|
16
|
|
|
|
50
|
|
|
|
|
|
|
|
25
|
|
Revisions other than price
|
|
|
13
|
|
|
|
(19
|
)
|
|
|
(1
|
)
|
|
|
7
|
|
Extensions and discoveries
|
|
|
46
|
|
|
|
139
|
|
|
|
2
|
|
|
|
72
|
|
Purchase of reserves
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
1
|
|
Production
|
|
|
(16
|
)
|
|
|
(227
|
)
|
|
|
(4
|
)
|
|
|
(58
|
)
|
Sale of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2007
|
|
|
388
|
|
|
|
1,844
|
|
|
|
39
|
|
|
|
734
|
|
Revisions due to prices
|
|
|
(349
|
)
|
|
|
(219
|
)
|
|
|
(2
|
)
|
|
|
(387
|
)
|
Revisions other than price
|
|
|
2
|
|
|
|
(12
|
)
|
|
|
|
|
|
|
|
|
Extensions and discoveries
|
|
|
120
|
|
|
|
111
|
|
|
|
2
|
|
|
|
141
|
|
Purchase of reserves
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(22
|
)
|
|
|
(212
|
)
|
|
|
(4
|
)
|
|
|
(61
|
)
|
Sale of reserves
|
|
|
(5
|
)
|
|
|
(4
|
)
|
|
|
|
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2008
|
|
|
134
|
|
|
|
1,510
|
|
|
|
35
|
|
|
|
421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
103
|
|
|
|
1,708
|
|
|
|
41
|
|
|
|
429
|
|
December 31, 2006
|
|
|
112
|
|
|
|
1,560
|
|
|
|
33
|
|
|
|
405
|
|
December 31, 2007
|
|
|
195
|
|
|
|
1,506
|
|
|
|
30
|
|
|
|
476
|
|
December 31, 2008
|
|
|
110
|
|
|
|
1,357
|
|
|
|
31
|
|
|
|
367
|
|
133
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International(1)
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Liquids
|
|
|
Total
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBoe)
|
|
|
Proved reserves as of December 31, 2005
|
|
|
129
|
|
|
|
22
|
|
|
|
|
|
|
|
132
|
|
Revisions due to prices
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
Revisions other than price
|
|
|
5
|
|
|
|
(12
|
)
|
|
|
|
|
|
|
3
|
|
Extensions and discoveries
|
|
|
14
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
14
|
|
Purchase of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(10
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
(10
|
)
|
Sale of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2006
|
|
|
135
|
|
|
|
8
|
|
|
|
|
|
|
|
137
|
|
Revisions due to prices
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
(10
|
)
|
Revisions other than price
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
Extensions and discoveries
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Purchase of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(20
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
(20
|
)
|
Sale of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2007
|
|
|
119
|
|
|
|
7
|
|
|
|
|
|
|
|
120
|
|
Revisions due to prices
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Revisions other than price
|
|
|
9
|
|
|
|
1
|
|
|
|
|
|
|
|
10
|
|
Extensions and discoveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(14
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
(15
|
)
|
Sale of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of December 31, 2008
|
|
|
128
|
|
|
|
6
|
|
|
|
|
|
|
|
129
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
54
|
|
|
|
22
|
|
|
|
|
|
|
|
57
|
|
December 31, 2006
|
|
|
59
|
|
|
|
8
|
|
|
|
|
|
|
|
60
|
|
December 31, 2007
|
|
|
48
|
|
|
|
6
|
|
|
|
|
|
|
|
49
|
|
December 31, 2008
|
|
|
58
|
|
|
|
6
|
|
|
|
|
|
|
|
59
|
|
|
|
|
(1) |
|
Included in the International quantities of proved reserves as
of December 31, 2008, 2007, 2006 and 2005 are
104 MMBoe, 86 MMBoe, 103 MMBoe and
105 MMBoe, respectively, which are attributable to
production sharing contracts with various foreign governments. |
Noteworthy amounts included in the categories of proved reserve
changes for the years 2008, 2007, 2006 and 2005 in the above
tables include:
|
|
|
|
|
Price Revisions Proved reserves must be
estimated using the assumption that
end-of-period
prices and costs remain constant for the duration of the
reservoir life. Due to significantly lower oil, gas and NGL
prices as of December 31, 2008 compared to prices as of
December 31, 2007, the estimated future net revenues
associated with certain of Devons proved reserves were no
longer positive. As a result, 473 MMBoe of reserves were
not considered proved as of December 31, 2008. Of the
|
134
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
473 MMBoe price revisions, 331 MMBoe related to
Devons Jackfish steam-assisted gravity drainage project in
Canada.
|
The 473 MMBoe price revision also includes 28 MMBoe
related to our proved reserves in the Canadian province of
Alberta. In December 2008, the provincial government of Alberta
enacted a new royalty regime. The new regime provides for new
royalties for conventional oil, gas, NGL and heavy oil
production effective January 1, 2009. As a result of the
newly enacted royalties, our proved reserves decreased as of
December 31, 2008.
|
|
|
|
|
Extensions and Discoveries:
|
2008 Of the 546 MMBoe of 2008 extensions and
discoveries, 252 MMBoe related to the Barnett Shale area in
Texas, 101 MMBoe related to Jackfish, 45 MMBoe related
to the Carthage area in east Texas, 21 MMBoe related to the
Cana shale development area in western Oklahoma, 19 MMBoe
related to the Lloydminster heavy oil development in Canada and
17 MMBoe related to the Woodford shale development area in
southeastern Oklahoma.
The 2008 extensions and discoveries included 420 MMBoe
related to additions from Devons infill drilling
activities, including 243 MMBoe related to the Barnett
Shale, 101 MMBoe related to Jackfish, 22 MMBoe related
to Carthage, 18 MMBoe related to Lloydminster and
11 MMBoe related to Cana.
2007 Of the 315 MMBoe of 2007 extensions
and discoveries, 119 MMBoe related to the Barnett Shale,
34 MMBoe related to Carthage, 22 MMBoe related to
Jackfish, 20 MMBoe related to Lloydminster, 17 MMBoe
related to Washakie and 15 MMBoe related to the Woodford
Shale.
The 2007 extensions and discoveries included 154 MMBoe
related to additions from Devons infill drilling
activities, including 96 MMBoe related to the Barnett Shale
and 19 MMBoe related to Lloydminster.
2006 Of the 433 MMBoe of 2006 extensions
and discoveries, 143 MMBoe related to the Barnett Shale,
88 MMBoe related to Jackfish, 30 MMBoe related to
Carthage and 20 MMBoe related to Washakie.
The 2006 extensions and discoveries included 202 MMBoe
related to additions from Devons infill drilling
activities, including 127 MMBoe related to the Barnett
Shale and 20 MMBoe related to Lloydminster.
|
|
|
|
|
Purchase of Reserves The 2008 total included
34 MMBoe located in Utah and 27 MMBoe located in the
Permian Basin. The 2006 total included 100 MMBoe located in
the Barnett Shale that was acquired in the June 2006 Chief
acquisition.
|
|
|
|
Revisions Other Than Price The 2008 total
included performance revisions of 22 MMBoe in the Barnett
Shale. The 2007 total included performance revisions of
39 MMBoe in the Barnett Shale, 13 MMBoe at Jackfish,
13 MMBoe in Carthage and seven MMBoe in China.
|
135
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Standardized
Measure of Discounted Future Net Cash Flows
The tables below reflect the standardized measure of discounted
future net continuing cash flows relating to Devons
interest in proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Future cash inflows
|
|
$
|
66,790
|
|
|
$
|
111,156
|
|
|
$
|
77,951
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
(9,340
|
)
|
|
|
(9,974
|
)
|
|
|
(8,116
|
)
|
Production
|
|
|
(30,719
|
)
|
|
|
(38,541
|
)
|
|
|
(28,107
|
)
|
Future income tax expense
|
|
|
(6,989
|
)
|
|
|
(17,930
|
)
|
|
|
(12,396
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
19,742
|
|
|
|
44,711
|
|
|
|
29,332
|
|
10% discount to reflect timing of cash flows
|
|
|
(9,250
|
)
|
|
|
(21,105
|
)
|
|
|
(13,581
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
10,492
|
|
|
$
|
23,606
|
|
|
$
|
15,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Future cash inflows
|
|
$
|
51,284
|
|
|
$
|
72,109
|
|
|
$
|
47,980
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
(6,887
|
)
|
|
|
(5,673
|
)
|
|
|
(4,919
|
)
|
Production
|
|
|
(24,113
|
)
|
|
|
(24,606
|
)
|
|
|
(18,428
|
)
|
Future income tax expense
|
|
|
(5,585
|
)
|
|
|
(12,704
|
)
|
|
|
(7,743
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
14,699
|
|
|
|
29,126
|
|
|
|
16,890
|
|
10% discount to reflect timing of cash flows
|
|
|
(7,318
|
)
|
|
|
(14,312
|
)
|
|
|
(8,091
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
7,381
|
|
|
$
|
14,814
|
|
|
$
|
8,799
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Future cash inflows
|
|
$
|
11,459
|
|
|
$
|
28,684
|
|
|
$
|
22,575
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
(1,623
|
)
|
|
|
(3,380
|
)
|
|
|
(2,395
|
)
|
Production
|
|
|
(4,984
|
)
|
|
|
(10,331
|
)
|
|
|
(7,431
|
)
|
Future income tax expense
|
|
|
(1,137
|
)
|
|
|
(3,729
|
)
|
|
|
(3,614
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
3,715
|
|
|
|
11,244
|
|
|
|
9,135
|
|
10% discount to reflect timing of cash flows
|
|
|
(1,463
|
)
|
|
|
(5,282
|
)
|
|
|
(4,318
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
2,252
|
|
|
$
|
5,962
|
|
|
$
|
4,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
136
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Future cash inflows
|
|
$
|
4,047
|
|
|
$
|
10,363
|
|
|
$
|
7,396
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
(830
|
)
|
|
|
(921
|
)
|
|
|
(802
|
)
|
Production
|
|
|
(1,622
|
)
|
|
|
(3,604
|
)
|
|
|
(2,248
|
)
|
Future income tax expense
|
|
|
(267
|
)
|
|
|
(1,497
|
)
|
|
|
(1,039
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
1,328
|
|
|
|
4,341
|
|
|
|
3,307
|
|
10% discount to reflect timing of cash flows
|
|
|
(469
|
)
|
|
|
(1,511
|
)
|
|
|
(1,172
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
859
|
|
|
$
|
2,830
|
|
|
$
|
2,135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows are computed by applying year-end prices
(averaging $32.65 per barrel of oil, $4.75 per Mcf of gas and
$16.54 per barrel of natural gas liquids at December 31,
2008) to the year-end quantities of proved reserves, except
in those instances where fixed and determinable price changes
are provided by contractual arrangements in existence at
year-end.
Future development and production costs are computed by
estimating the expenditures to be incurred in developing and
producing proved oil and gas reserves at the end of the year,
based on year-end costs and assuming continuation of existing
economic conditions. Of the $9.3 billion of future
development costs as of the end of 2008, $1.7 billion,
$1.6 billion and $1.5 billion are estimated to be
spent in 2009, 2010 and 2011, respectively.
Future development costs include not only development costs, but
also future dismantlement, abandonment and rehabilitation costs.
Included as part of the $9.3 billion of future development
costs are $2.0 billion of future dismantlement, abandonment
and rehabilitation costs.
Future production costs include general and administrative
expenses directly related to oil and gas producing activities.
Future income tax expenses are computed by applying the
appropriate statutory tax rates to the future pre-tax net cash
flows relating to proved reserves, net of the tax basis of the
properties involved. The future income tax expenses give effect
to permanent differences and tax credits, but do not reflect the
impact of future operations.
137
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Changes
Relating to the Standardized Measure of Discounted Future Net
Cash Flows
Principal changes in the standardized measure of discounted
future net continuing cash flows attributable to Devons
proved reserves are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Beginning balance
|
|
$
|
23,606
|
|
|
$
|
15,751
|
|
|
$
|
21,629
|
|
Oil, gas and NGL sales, net of production costs
|
|
|
(10,135
|
)
|
|
|
(7,242
|
)
|
|
|
(6,157
|
)
|
Net changes in prices and production costs
|
|
|
(16,013
|
)
|
|
|
9,550
|
|
|
|
(10,275
|
)
|
Extensions and discoveries, net of future development costs
|
|
|
1,889
|
|
|
|
4,162
|
|
|
|
4,586
|
|
Purchase of reserves, net of future development costs
|
|
|
214
|
|
|
|
51
|
|
|
|
800
|
|
Development costs incurred during the period that reduced future
development costs
|
|
|
1,790
|
|
|
|
1,887
|
|
|
|
1,466
|
|
Revisions of quantity estimates
|
|
|
(1,674
|
)
|
|
|
578
|
|
|
|
(2,199
|
)
|
Sales of reserves in place
|
|
|
(8
|
)
|
|
|
(51
|
)
|
|
|
(10
|
)
|
Accretion of discount
|
|
|
3,307
|
|
|
|
2,232
|
|
|
|
3,234
|
|
Net change in income taxes
|
|
|
5,773
|
|
|
|
(2,879
|
)
|
|
|
4,143
|
|
Other, primarily changes in timing and foreign exchange rates
|
|
|
1,743
|
|
|
|
(433
|
)
|
|
|
(1,466
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
$
|
10,492
|
|
|
$
|
23,606
|
|
|
$
|
15,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21.
|
Supplemental
Quarterly Financial Information (Unaudited)
|
Following is a summary of the unaudited interim results of
operations for the years ended December 31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Full
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year
|
|
|
|
(In millions, except per share amounts)
|
|
|
Revenues
|
|
$
|
2,975
|
|
|
$
|
3,548
|
|
|
$
|
5,978
|
|
|
$
|
2,710
|
|
|
$
|
15,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations
|
|
$
|
651
|
|
|
$
|
594
|
|
|
$
|
2,509
|
|
|
|
(6,833
|
)
|
|
$
|
(3,079
|
)
|
Earnings from discontinued operations
|
|
|
98
|
|
|
|
707
|
|
|
|
109
|
|
|
|
17
|
|
|
|
931
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
$
|
749
|
|
|
$
|
1,301
|
|
|
$
|
2,618
|
|
|
|
(6,816
|
)
|
|
$
|
(2,148
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations
|
|
$
|
1.46
|
|
|
$
|
1.33
|
|
|
$
|
5.67
|
|
|
$
|
(15.46
|
)
|
|
$
|
(6.95
|
)
|
Earnings from discontinued operations
|
|
|
0.22
|
|
|
|
1.58
|
|
|
|
0.25
|
|
|
|
0.04
|
|
|
|
2.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
$
|
1.68
|
|
|
$
|
2.91
|
|
|
$
|
5.92
|
|
|
$
|
(15.42
|
)
|
|
$
|
(4.85
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations
|
|
$
|
1.44
|
|
|
$
|
1.31
|
|
|
$
|
5.63
|
|
|
$
|
(15.46
|
)
|
|
$
|
(6.95
|
)
|
Earnings from discontinued operations
|
|
|
0.22
|
|
|
|
1.57
|
|
|
|
0.24
|
|
|
|
0.04
|
|
|
|
2.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
$
|
1.66
|
|
|
$
|
2.88
|
|
|
$
|
5.87
|
|
|
$
|
(15.42
|
)
|
|
$
|
(4.85
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
138
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Full
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year
|
|
|
|
(In millions, except per share amounts)
|
|
|
Revenues
|
|
$
|
2,473
|
|
|
$
|
2,929
|
|
|
$
|
2,763
|
|
|
$
|
3,197
|
|
|
$
|
11,362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations
|
|
$
|
574
|
|
|
$
|
824
|
|
|
$
|
644
|
|
|
$
|
1,104
|
|
|
$
|
3,146
|
|
Earnings from discontinued operations
|
|
|
77
|
|
|
|
80
|
|
|
|
91
|
|
|
|
212
|
|
|
|
460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
651
|
|
|
$
|
904
|
|
|
$
|
735
|
|
|
$
|
1,316
|
|
|
$
|
3,606
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations
|
|
$
|
1.29
|
|
|
$
|
1.84
|
|
|
$
|
1.45
|
|
|
$
|
2.48
|
|
|
$
|
7.05
|
|
Earnings from discontinued operations
|
|
|
0.17
|
|
|
|
0.18
|
|
|
|
0.20
|
|
|
|
0.48
|
|
|
|
1.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
1.46
|
|
|
$
|
2.02
|
|
|
$
|
1.65
|
|
|
$
|
2.96
|
|
|
$
|
8.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations
|
|
$
|
1.27
|
|
|
$
|
1.82
|
|
|
$
|
1.43
|
|
|
$
|
2.45
|
|
|
$
|
6.97
|
|
Earnings from discontinued operations
|
|
|
0.17
|
|
|
|
0.18
|
|
|
|
0.20
|
|
|
|
0.47
|
|
|
|
1.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
1.44
|
|
|
$
|
2.00
|
|
|
$
|
1.63
|
|
|
$
|
2.92
|
|
|
$
|
8.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
(Loss) from Continuing Operations
The fourth quarter of 2008 includes reductions of the carrying
values of oil and gas properties totaling $10.4 billion
($7.1 billion after income taxes, or $16.10 per diluted
share).
The first and second quarters of 2008 include unrealized losses
on our commodity hedges of $780 million ($499 million
after income taxes, or $1.11 per diluted share) and
$912 million ($584 million after income taxes, or
$1.30 per diluted share), respectively, as a result of increases
in gas prices subsequent to our trade dates. The third quarter
of 2008 includes a net unrealized gain of $1.8 billion
($1.2 billion after income taxes, or $2.63 per diluted
share), resulting from a decrease in gas prices.
The second quarter of 2008 includes an increase to income tax
expense from continuing operations of $312 million (or
$0.70 per diluted share) due to repatriations from certain
foreign subsidiaries to the United States and tax policy
election changes.
The second and fourth quarters of 2007 include a reduction to
income tax expense from continuing operations of
$30 million (or $0.07 per diluted share) and
$231 million (or $0.52 per diluted share), respectively,
due to statutory rate reductions in Canada.
Earnings
from Discontinued Operations
The second quarter of 2008 includes a $623 million gain
($529 million after income taxes, or $1.17 per diluted
share) as a result of completing the sale of Devons
Equatorial Guinea operations. Also, during the second quarter of
2008, Devon closed the sale of its Gabon operations, which
resulted in a $114 million gain ($111 million after
income taxes, or $0.25 per diluted share).
The third quarter of 2008 includes an $83 million gain
($101 million after income taxes, or $0.23 per diluted
share) as a result of completing the sale of Devons assets
in Cote dIvoire.
The second quarter of 2007 includes a reduction of carrying
value of oil and gas properties of $64 million
($13 million after income taxes, or $0.03 per diluted
share).
The fourth quarter of 2007 includes a $90 million gain
($90 million after income taxes, or $0.20 per diluted
share) as a result of completing the sale of Devons assets
in Egypt in October 2007.
139
|
|
Item 9.
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure
|
Not Applicable.
|
|
Item 9A.
|
Controls
and Procedures
|
Disclosure
Controls and Procedures
We have established disclosure controls and procedures to ensure
that material information relating to Devon, including its
consolidated subsidiaries, is made known to the officers who
certify Devons financial reports and to other members of
senior management and the Board of Directors.
Based on their evaluation, Devons principal executive and
principal financial officers have concluded that Devons
disclosure controls and procedures (as defined in
Rules 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934) were effective
as of December 31, 2008 to ensure that the information
required to be disclosed by Devon in the reports that it files
or submits under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time
periods specified in the SEC rules and forms.
Managements
Annual Report on Internal Control Over Financial
Reporting
Devons management is responsible for establishing and
maintaining adequate internal control over financial reporting
for Devon, as such term is defined in
Rules 13a-15(f)
and
15d-15(f)
under the Securities Exchange Act of 1934. Under the supervision
and with the participation of Devons management, including
our principal executive and principal financial officers, Devon
conducted an evaluation of the effectiveness of its internal
control over financial reporting based on the framework in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (the COSO Framework). Based on this
evaluation under the COSO Framework, which was completed on
February 20, 2009, management concluded that its internal
control over financial reporting was effective as of
December 31, 2008.
The effectiveness of Devons internal control over
financial reporting as of December 31, 2008 has been
audited by KPMG LLP, an independent registered public accounting
firm who audited Devons consolidated financial statements
as of and for the year ended December 31, 2008, as stated
in their report, which is included under Item 8.
Financial Statements and Supplementary Data.
Changes
in Internal Control Over Financial Reporting
There was no change in Devons internal control over
financial reporting during the fourth quarter of 2008 that has
materially affected, or is reasonably likely to materially
affect, Devons internal control over financial reporting.
|
|
Item 9B.
|
Other
Information
|
Not applicable.
140
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
The information called for by this Item 10 is incorporated
hereby by reference to the definitive Proxy Statement to be
filed by Devon pursuant to Regulation 14A of the General
Rules and Regulations under the Securities Exchange Act of 1934
not later than April 30, 2009.
|
|
Item 11.
|
Executive
Compensation
|
The information called for by this Item 11 is incorporated
herein by reference to the definitive Proxy Statement to be
filed by Devon pursuant to Regulation 14A of the General
Rules and Regulations under the Securities Exchange Act of 1934
not later than April 30, 2009.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
The information called for by this Item 12 is incorporated
herein by reference to the definitive Proxy Statement to be
filed by Devon pursuant to Regulation 14A of the General
Rules and Regulations under the Securities Exchange Act of 1934
not later than April 30, 2009.
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
The information called for by this Item 13 is incorporated
herein by reference to the definitive Proxy Statement to be
filed by Devon pursuant to Regulation 14A of the General
Rules and Regulations under the Securities Exchange Act of 1934
not later than April 30, 2009.
|
|
Item 14.
|
Principal
Accounting Fees and Services
|
The information called for by this Item 14 is incorporated
herein by reference to the definitive Proxy Statement to be
filed by Devon pursuant to Regulation 14A of the General
Rules and Regulations under the Securities Exchange Act of 1934
not later than April 30, 2009.
141
PART IV
|
|
Item 15.
|
Exhibits
and Financial Statement Schedules
|
(a) The following documents are filed as part of this
report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial
Statements and Consolidated Financial Statement Schedules
appearing at Item 8. Financial Statements and
Supplementary Data in this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they are
inapplicable, or the required information has been included in
the consolidated financial statements or notes thereto.
3. Exhibits
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
1
|
.1
|
|
Underwriting Agreement, dated as of January 6, 2009, among
Devon Energy Corporation and Banc of America Securities LLC,
J.P. Morgan Securities Inc. and UBS Securities LLC, as
representatives of the several Underwriters named therein
(incorporated by reference to Exhibit 1.1 to
Registrants
Form 8-K
filed on January 9, 2009).
|
|
2
|
.1
|
|
Agreement and Plan of Merger, dated as of February 23,
2003, by and among Registrant, Devon NewCo Corporation, and
Ocean Energy, Inc. (incorporated by reference to
Registrants Amendment No. 1 to
Form S-4
Registration
No. 333-103679,
filed on March 20, 2003).
|
|
2
|
.2
|
|
Amended and Restated Agreement and Plan of Merger, dated as of
August 13, 2001, by and among Registrant, Devon NewCo
Corporation, Devon Holdco Corporation, Devon Merger Corporation,
Mitchell Merger Corporation and Mitchell Energy &
Development Corp. (incorporated by reference to Annex A to
Registrants Joint Proxy Statement/Prospectus of
Form S-4
Registration Statement
No. 333-68694
as filed on August 30, 2001).
|
|
2
|
.3
|
|
Offer to Purchase for Cash and Directors Circular dated
September 6, 2001 (incorporated by reference to
Registrants and Devon Acquisition Corporations
Schedule 14D-1F
filed on September 6, 2001).
|
|
2
|
.4
|
|
Pre-Acquisition Agreement, dated as of August 31, 2001,
between Registrant and Anderson Exploration Ltd. (incorporated
by reference to Exhibit 2.2 to Registrants
Registration Statement on
Form S-4,
File
No. 333-68694
as filed on September 14, 2001).
|
|
2
|
.5
|
|
Amendment No. One, dated as of July 11, 2000, to
Agreement and Plan of Merger by and among Registrant, Devon
Merger Co. and Santa Fe Snyder Corporation dated as of
May 25, 2000 (incorporated by reference to Exhibit 2.1
to Registrants
Form 8-K
filed on July 12, 2000).
|
|
2
|
.6
|
|
Amended and Restated Agreement and Plan of Merger among
Registrant, Devon Energy Corporation (Oklahoma), Devon Oklahoma
Corporation and PennzEnergy Company dated as of May 19,
1999 (incorporated by reference to Exhibit 2.1 to
Registrants
Form S-4,
File
No. 333-82903
filed on July 15, 1999).
|
|
3
|
.1
|
|
Registrants Restated Certificate of Incorporation
(incorporated by reference to Exhibit 3.1 of
Registrants
Form 10-K
filed on March 9, 2005).
|
|
3
|
.2
|
|
Registrants Certificate of Amendment of Restated
Certificate of Incorporation (incorporated by reference to
Exhibit 3.1 of Registrants
Form 10-Q
filed on August 7, 2008).
|
|
3
|
.3
|
|
Registrants Bylaws (incorporated by reference to
Exhibit 3.2 of Registrants
Form 10-K
filed on March 3, 2006).
|
|
4
|
.1
|
|
Rights Agreement dated as of August 17, 1999 between
Registrant and BankBoston, N.A. (incorporated by reference to
Exhibit 4.2 to Registrants
Form 8-K
filed on August 18, 1999).
|
|
4
|
.2
|
|
Amendment to Rights Agreement, dated as of May 25, 2000, by
and between Registrant and Fleet National Bank, formerly
BankBoston, N.A. (incorporated by reference to Exhibit 4.2
to Registrants
Form S-4
filed on June 22, 2000).
|
142
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
4
|
.3
|
|
Amendment to Rights Agreement, dated as of October 4, 2001,
by and between Registrant and Fleet National Bank, formerly Bank
Boston, N.A. (incorporated by reference to Exhibit 99.1 to
Registrants
Form 8-K
filed on October 11, 2001).
|
|
4
|
.4
|
|
Amendment to Rights Agreement, dated September 13, 2002,
between Registrant and Wachovia Bank, N.A. (incorporated by
reference to Exhibit 4.9 to Registrants Registration
Statement on
Form S-3
File Nos.
333-83156,
333-83156-1,
and
333-83156-2
as filed on October 4, 2002).
|
|
4
|
.5
|
|
Amendment to Rights Agreement, dated as of August 1, 2006,
by and between Registrant and Computershare Trust Company,
N.A. (formerly UMB Bank, n.a.) (incorporated by reference to
Exhibit 4.4 to Registrants
Form 10-Q
filed on August 4, 2006).
|
|
4
|
.6
|
|
Indenture, dated as of March 1, 2002, between Registrant
and The Bank of New York Mellon Trust Company, N.A., as
Trustee, relating to senior debt securities issuable by
Registrant (the Senior Indenture) (incorporated by
reference to Exhibit 4.1 of Registrants
Form 8-K
filed on April 9, 2002).
|
|
4
|
.7
|
|
Supplemental Indenture No. 1, dated as of March 25,
2002, to Indenture dated as of March 1, 2002, between
Registrant and The Bank of New York Mellon Trust Company,
N.A., as Trustee, relating to the 7.95% Senior Debentures
due 2032 (incorporated by reference to Exhibit 4.2 to
Registrants
Form 8-K
filed on April 9, 2002).
|
|
4
|
.8
|
|
Supplemental Indenture No. 3, dated as of January 9,
2009, to Indenture dated as of March 1, 2002, between
Registrant and The Bank of New York Mellon Trust Company,
N.A., as Trustee, relating to the 5.625% Senior Notes due
2014 and the 6.30% Senior Notes due 2019 (incorporated by
reference to Exhibit 4.1 to Registrants
Form 8-K
filed on January 9, 2009).
|
|
4
|
.9
|
|
Indenture dated as of October 3, 2001, by and among Devon
Financing Corporation, U.L.C. as Issuer, Registrant as
Guarantor, and The Bank of New York Mellon Trust Company,
N.A., originally The Chase Manhattan Bank, as Trustee, relating
to the 6.875% Senior Notes due 2011 and the
7.875% Debentures due 2031 (incorporated by reference to
Exhibit 4.7 to Registrants Registration Statement on
Form S-4,
File
No. 333-68694
as filed on October 31, 2001).
|
|
4
|
.10
|
|
Indenture dated as of February 15, 1986 among Registrant
(as successor by merger to PennzEnergy Company, formerly
Pennzoil Company) and The Bank of New York Mellon
Trust Company, N.A., originally Mellon Bank, N.A., as
Trustee (incorporated by reference to Exhibit 4(a) to
Pennzoil Companys
Form 10-Q
for the quarter ended June 30, 1986 (SEC File
No. 1-5591)).
|
|
4
|
.11
|
|
First Supplemental Indenture dated as of August 17, 1999 to
Indenture dated as of February 15, 1986 among Registrant
(as successor by merger to PennzEnergy Company, formerly
Pennzoil Company) and The Bank of New York Mellon
Trust Company, N.A., originally Chase Bank of Texas,
National Association, as Trustee, supplementing the terms of the
10.125% Debentures due 2009, (incorporated by reference to
Exhibit 4.8 to Registrants
Form 8-K
filed on August 18, 1999).
|
|
4
|
.12
|
|
Senior Indenture dated as of September 28, 2001 among Devon
OEI Operating, Inc. (as successor by merger to Ocean Energy,
Inc.) and The Bank of New York Mellon Trust Company, N.A.,
as Trustee (incorporated by reference to Exhibit 4.1 to
Ocean Energy, Inc.s Current Report on
Form 8-K
filed on September 28, 2001). Officers Certificate
establishing the terms of the 7.25% Senior Notes due 2011,
including the form of global note relating thereto (incorporated
by reference to Exhibit 4.2 to Ocean Energy, Inc.s
Current Report on
Form 8-K
filed on September 28, 2001).
|
|
4
|
.13
|
|
First Supplemental Indenture, dated December 31, 2005 to
Indenture dated as of September 28, 2001 among Devon OEI
Operating, Inc. as Issuer, Devon Energy Production Company, L.P.
as Successor Guarantor and The Bank of New York Mellon
Trust Company, N.A., as Trustee, relating to the
7.25% Senior Notes due 2011 (incorporated by reference to
Exhibit 4.19 of Registrants
Form 10-K
filed on March 3, 2006).
|
|
4
|
.14
|
|
Indenture dated as of July 8, 1998 among Devon OEI
Operating, Inc. (as successor by merger to Ocean Energy, Inc.),
its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A.,
as Trustee, relating to the 8.25% Senior Notes due 2018
(incorporated by reference to Exhibit 10.24 to the
Form 10-Q
for the period ended June 30, 1998 of Ocean Energy, Inc.
(Registration
No. 0-25058)).
|
143
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
4
|
.15
|
|
First Supplemental Indenture, dated March 30, 1999 to
Indenture dated as of July 8, 1998 among Devon OEI
Operating, Inc. (as successor by merger to Ocean Energy, Inc.),
its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A.,
as Trustee, relating to the 8.25% Senior Notes due 2018
(incorporated by reference to Exhibit 4.5 to Ocean Energy,
Inc.s
Form 10-Q
for the period ended March 31, 1999).
|
|
4
|
.16
|
|
Second Supplemental Indenture, dated as of May 9, 2001 to
Indenture dated as of July 8, 1998 among Devon OEI
Operating, Inc. (as successor by merger to Ocean Energy, Inc.),
its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A.,
as Trustee, relating to the 8.25% Senior Notes due 2018
(incorporated by reference to Exhibit 99.2 to Ocean Energy,
Inc.s Current Report on
Form 8-K
filed on May 14, 2001).
|
|
4
|
.17
|
|
Third Supplemental Indenture, dated January 23, 2006 to
Indenture dated as of July 8, 1998 among Devon OEI
Operating, Inc. as Issuer, Devon Energy Production Company, L.P.
as Successor Guarantor, and Wells Fargo Bank Minnesota, N.A., as
Trustee, relating to the 8.25% Senior Notes due 2018
(incorporated by reference to Exhibit 4.23 of
Registrants
Form 10-K
filed on March 3, 2006).
|
|
4
|
.18
|
|
Senior Indenture dated September 1, 1997, among Devon OEI
Operating, Inc. (as successor by merger to Ocean Energy, Inc.)
and The Bank of New York Mellon Trust Company, N.A., as
Trustee, and Specimen of 7.50% Senior Notes (incorporated
by reference to Exhibit 4.4 to Ocean Energys Annual
Report on
Form 10-K
for the year ended December 31, 1997)).
|
|
4
|
.19
|
|
First Supplemental Indenture, dated as of March 30, 1999 to
Senior Indenture dated as of September 1, 1997, among Devon
OEI Operating, Inc. (as successor by merger to Ocean Energy,
Inc.) and The Bank of New York Mellon Trust Company, N.A.,
as Trustee, relating to the 7.50% Senior Notes Due 2027
(incorporated by reference to Exhibit 4.10 to Ocean
Energys
Form 10-Q
for the period ended March 31, 1999).
|
|
4
|
.20
|
|
Second Supplemental Indenture, dated as of May 9, 2001 to
Senior Indenture dated as of September 1, 1997, among Devon
OEI Operating, Inc. (as successor by merger to Ocean Energy,
Inc.), its Subsidiary Guarantors, and The Bank of New York
Mellon Trust Company, N.A., as Trustee, relating to the
7.50% Senior Notes (incorporated by reference to
Exhibit 99.4 to Ocean Energy, Inc.s Current Report on
Form 8-K
filed with the SEC on May 14, 2001).
|
|
4
|
.21
|
|
Third Supplemental Indenture, dated December 31, 2005 to
Senior Indenture dated as of September 1, 1997, among Devon
OEI Operating, Inc. as Issuer, Devon Energy Production Company,
L.P. as Successor Guarantor, and The Bank of New York Mellon
Trust Company, N.A.., as Trustee, relating to the
7.50% Senior Notes (incorporated by reference to
Exhibit 4.27 of Registrants
Form 10-K
filed on March 3, 2006).
|
|
10
|
.1
|
|
Amended and Restated Investor Rights Agreement, dated as of
August 13, 2001, by and among Registrant, Devon Holdco
Corporation, George P. Mitchell and Cynthia Woods Mitchell
(incorporated by reference to Annex C to the Joint Proxy
Statement/Prospectus of
Form S-4
Registration Statement
No. 333-68694
filed on August 30, 2001).
|
|
10
|
.2
|
|
First Amendment to Credit Agreement dated as of
December 19, 2007, among Registrant as Borrower, Bank of
America, N.A., individually and as Administrative Agent and the
Lenders party thereto (incorporated by reference to
Exhibit 10.3 to Registrants
Form 10-K
filed on February 28, 2008).
|
|
10
|
.3
|
|
Amended and Restated Credit Agreement dated March 24, 2006,
effective as of April 7, 2006, among Registrant as US
Borrower, Northstar Energy Corporation and Devon Canada
Corporation as Canadian Borrowers, Bank of America, N.A. as
Administrative Agent, Swing Line Lender and L/C Issuer; JPMorgan
Chase Bank, N.A. as Syndication Agent, Bank of Montreal D/B/A
Harris Nesbitt, Royal Bank of Canada, Wachovia Bank,
National Association as Co-Documentation Agents and The Other
Lenders Party Hereto, Banc of America Securities L.L.C. and
J.P. Morgan Securities Inc., as Joint Lead Arrangers and
Book Managers for the $2.0 billion five-year revolving
credit facility (incorporated by reference to Exhibit 10.1
to Registrants
Form 10-Q
filed on May 4, 2006).
|
|
10
|
.4
|
|
First Amendment to Amended and Restated Credit Agreement dated
as of June 1, 2006, among Registrant as the US Borrower,
Northstar Energy Corporation and Devon Canada Corporation as the
Canadian Borrowers, Bank of America, N.A., individually and as
Administrative Agent and the Lenders party to this Amendment
(incorporated by reference to Exhibit 10.2 to
Registrants
Form 10-Q
filed on November 7, 2007).
|
144
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
10
|
.5
|
|
Second Amendment to Amended and Restated Credit Agreement dated
as of September 19, 2007, among Registrant as the US
Borrower, Northstar Energy Corporation and Devon Canada
Corporation as the Canadian Borrowers, Bank of America, N.A.,
individually and as Administrative Agent and the Lenders party
to this Amendment. (incorporated by reference to
Exhibit 10.3 to Registrants
Form 10-Q
filed on November 7, 2007).
|
|
10
|
.6
|
|
Third Amendment to Amended and Restated Credit Agreement dated
as of December 19, 2007, among Registrant as the US
Borrower, Northstar Energy Corporation and Devon Canada
Corporation as the Canadian Borrowers, Bank of America, N.A.,
individually and as Administrative Agent and the Lenders party
thereto (incorporated by reference to Exhibit 10.7 to
Registrants
Form 10-K
filed on February 28, 2008).
|
|
10
|
.7
|
|
Fourth Amendment to Amended and Restated Credit Agreement dated
as of April 7, 2008, among Registrant as US Borrower,
Northstar Energy Corporation and Devon Canada Corporation as the
Canadian Borrowers, Bank of America, N.A., individually and as
Administrative Agent and the Lenders party thereto (incorporated
by reference to Exhibit 10.1 of Registrants
Form 10-Q
filed on May 7, 2008).
|
|
10
|
.8
|
|
Fifth Amendment to Amended and Restated Credit Agreement dated
as of November 5, 2008, among Registrant as US Borrower,
Northstar Energy Corporation and Devon Canada Corporation as the
Canadian Borrowers, Bank of America, N.A., individually and as
Administrative Agent, and the Lenders party thereto
(incorporated by reference to Exhibit 10.2 of
Registrants
Form 10-Q
filed on November 6, 2008).
|
|
10
|
.9
|
|
364-Day
Credit Agreement dated as of November 5, 2008 among
Registrant as Borrower, Bank of America, N.A. as Administrative
Agent, JPMorgan Chase Bank, N.A. as Syndication Agent, and The
Other Lenders party thereto, Banc of America Securities LLC and
J.P. Morgan Securities, Inc. as Joint Lead Arrangers and
Book Managers for the $700 Million Short-Term Credit Facility
(incorporated by reference to Exhibit 10.1 of
Registrants
Form 10-Q
filed on November 6, 2008).
|
|
10
|
.10
|
|
Devon Energy Corporation 2005 Long-Term Incentive Plan
(incorporated by reference to Registrants
Form S-8
Registration
No. 333-127630,
filed August 17, 2005).*
|
|
10
|
.11
|
|
First Amendment to Devon Energy Corporation 2005 Long-Term
Incentive Plan (incorporated by reference to Appendix A to
Registrants Proxy Statement for the 2006 Annual Meeting of
Stockholders filed on April 28, 2006).*
|
|
10
|
.12
|
|
Devon Energy Corporation 2003 Long-Term Incentive Plan
(incorporated by reference to Registrants
Form S-8
Registration
No. 333-104922,
filed May 1, 2003).*
|
|
10
|
.13
|
|
Devon Energy Corporation 1997 Stock Option Plan (as amended
August 29, 2000) (incorporated by reference to
Exhibit A to Registrants Proxy Statement for the 1997
Annual Meeting of Shareholders filed on April 3, 1997).*
|
|
10
|
.14
|
|
Ocean Energy, Inc. 1999 Long Term Incentive Plan (incorporated
by reference to Registrants Post Effective Amendment
No. 1 to
Form S-4
on
Form S-8
Registration
No. 333-103679,
filed on April 28, 2003).*
|
|
10
|
.15
|
|
Ocean Energy, Inc. 2001 Long Term Incentive Plan (incorporated
by reference to Registrants Post Effective Amendment
No. 1 to
Form S-4
on
Form S-8
Registration
No. 333-103679,
filed on April 28, 2003).*
|
|
10
|
.16
|
|
Santa Fe Energy Resources Incentive Compensation Plan, as
amended (incorporated by reference to Exhibit 10(a) to
Santa Fe Energy Resources, Inc.s Annual Report on
Form 10-K
for the year ended December 31, 1998).*
|
|
10
|
.17
|
|
Santa Fe Energy Resources 1990 Incentive Stock Compensation
Plan, Third Amendment and Restatement (incorporated by reference
to Exhibit 10(a) to Santa Fe Energy Resources, Inc.s
Quarterly Report on
Form 10-Q
for the quarter ended March 31, 1996).*
|
|
10
|
.18
|
|
Santa Fe Energy Resources, Inc. Supplemental Retirement Plan
effective as of December 4, 1990 (incorporated by reference
to Exhibit 10(h) to Santa Fe Energy Resources, Inc.s
Annual Report on
Form 10-K
for the year ended December 31, 1996).*
|
145
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
10
|
.19
|
|
Amended and Restated Form of Employment Agreement between
Registrant and Stephen J. Hadden, R. Alan Marcum, J. Larry
Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette,
Lyndon C. Taylor and William F. Whitsitt dated December 15,
2008.*
|
|
10
|
.20
|
|
Form of Award Agreement between Registrant and Stephen J.
Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W.
Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F.
Whitsitt for stock options granted from the 2005 Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.39
to Registrants
Form 10-Q
filed on August 4, 2005).*
|
|
10
|
.21
|
|
Form of Amendment to Nonqualified Stock Option Award Agreements
under the Devon Energy Corporation 2005 Long-Term Incentive Plan
between Registrant and Stephen J. Hadden, R. Alan Marcum, J.
Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette,
Lyndon C. Taylor and William F. Whitsitt (incorporated by
reference to Exhibit 10.1 of Registrants
Form 10-Q
filed on August 7, 2008).*
|
|
10
|
.22
|
|
Form of Award Agreement between Registrant and all
Non-Management Directors for stock options granted from the 2005
Long-Term Incentive Plan (incorporated by reference to
Exhibit 10.40 to Registrants
Form 10-Q
filed on August 4, 2005).*
|
|
10
|
.23
|
|
Form of Non-Management Director Nonqualified Stock Option Award
Agreement under the Devon Energy Corporation 2005 Long-Term
Incentive Plan between Registrant and all Non-Management
Directors (incorporated by reference to Exhibit 10.3 of
Registrants
Form 10-Q
filed on August 7, 2008).*
|
|
10
|
.24
|
|
Form of Award Agreement from the 2005 Long-Term Incentive Plan
between Registrant and Stephen J. Hadden, R. Alan Marcum, J.
Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette,
Lyndon C. Taylor, William F. Whitsitt and all Non-Management
Directors for restricted stock awards (incorporated by reference
to Exhibit 10.41 to Registrants
Form 10-Q
filed on August 4, 2005).*
|
|
10
|
.25
|
|
Form of Amendment to Restricted Stock Award Agreements under the
Devon Energy Corporation 2005 Long-Term Incentive Plan between
Registrant and Stephen J. Hadden, R. Alan Marcum, J. Larry
Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette,
Lyndon C. Taylor and William F. Whitsitt (incorporated by
reference to Exhibit 10.2 of Registrants
Form 10-Q
filed on August 7, 2008).*
|
|
10
|
.26
|
|
Form of Non-Management Director Restricted Stock Award Agreement
under the Devon Energy Corporation 2005 Long-Term Incentive Plan
between Registrant and all Non-Management Directors
(incorporated by reference to Exhibit 10.4 of
Registrants
Form 10-Q
filed on August 7, 2008).*
|
|
10
|
.27
|
|
Amended and Restated Severance Agreement between Registrant and
Danny J. Heatly, dated December 15, 2008.*
|
|
12
|
|
|
Statement of computations of ratios of earnings to fixed charges
and to combined fixed charges and preferred stock dividends.
|
|
21
|
|
|
Registrants Significant Subsidiaries.
|
|
23
|
.1
|
|
Consent of KPMG LLP.
|
|
23
|
.2
|
|
Consent of LaRoche Petroleum Consultants.
|
|
23
|
.3
|
|
Consent of Ryder Scott Company, L.P.
|
|
23
|
.4
|
|
Consent of AJM Petroleum Consultants.
|
|
31
|
.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer of
Registrant, pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
31
|
.2
|
|
Certification of Danny J. Heatly, Senior Vice
President Accounting and Chief Accounting Officer of
Registrant, pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
32
|
.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer of
Registrant, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
|
|
32
|
.2
|
|
Certification of Danny J. Heatly, Senior Vice
President Accounting and Chief Accounting Officer of
Registrant, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the
Sarbanes-Oxley
Act of 2002.
|
|
|
|
* |
|
Compensatory plans or arrangements |
146
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
DEVON ENERGY CORPORATION
J. Larry Nichols,
Chairman of the Board and
Chief Executive Officer
February 27, 2009
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the Registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
|
|
|
|
|
/s/ J.
Larry Nichols
J.
Larry Nichols
|
|
Chairman of the Board, Chief
Executive Officer and Director
|
|
February 27, 2009
|
|
|
|
|
|
/s/ John
Richels
John
Richels
|
|
President and Director
|
|
February 27, 2009
|
|
|
|
|
|
/s/ Danny
J. Heatly
Danny
J. Heatly
|
|
Senior Vice President Accounting and Chief
Accounting Officer
|
|
February 27, 2009
|
|
|
|
|
|
/s/ Thomas
F. Ferguson
Thomas
F. Ferguson
|
|
Director
|
|
February 27, 2009
|
|
|
|
|
|
/s/ David
A. Hager
David
A. Hager
|
|
Director
|
|
February 27, 2009
|
|
|
|
|
|
/s/ John
A. Hill
John
A. Hill
|
|
Director
|
|
February 27, 2009
|
|
|
|
|
|
/s/ Robert
L. Howard
Robert
L. Howard
|
|
Director
|
|
February 27, 2009
|
|
|
|
|
|
/s/ Michael
M. Kanovsky
Michael
M. Kanovsky
|
|
Director
|
|
February 27, 2009
|
|
|
|
|
|
/s/ J.
Todd Mitchell
J.
Todd Mitchell
|
|
Director
|
|
February 27, 2009
|
|
|
|
|
|
/s/ Mary
P. Ricciardello
Mary
P. Ricciardello
|
|
Director
|
|
February 27, 2009
|
147
INDEX TO
EXHIBITS
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
10
|
.19
|
|
Amended and Restated Form of Employment Agreement between
Registrant and Stephen J. Hadden, R. Alan Marcum, J. Larry
Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette,
Lyndon C. Taylor and William F. Whitsitt dated December 15,
2008.*
|
|
10
|
.27
|
|
Amended and Restated Severance Agreement between Registrant and
Danny J. Heatly, dated December 15, 2008.*
|
|
12
|
|
|
Statement of computations of ratios of earnings to fixed charges
and to combined fixed charges and preferred stock dividends.
|
|
21
|
|
|
Registrants Significant Subsidiaries.
|
|
23
|
.1
|
|
Consent of KPMG LLP.
|
|
23
|
.2
|
|
Consent of LaRoche Petroleum Consultants.
|
|
23
|
.3
|
|
Consent of Ryder Scott Company, L.P.
|
|
23
|
.4
|
|
Consent of AJM Petroleum Consultants.
|
|
31
|
.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer of
Registrant, pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
31
|
.2
|
|
Certification of Danny J. Heatly, Senior Vice
President Accounting and Chief Accounting Officer of
Registrant, pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
32
|
.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer of
Registrant, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
|
|
32
|
.2
|
|
Certification of Danny J. Heatly, Senior Vice President
Accounting and Chief Accounting Officer of
Registrant, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the
Sarbanes-Oxley
Act of 2002.
|
|
|
|
* |
|
Compensatory plans or arrangements |