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,
2009
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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 whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). 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. o
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
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Smaller reporting company
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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 30, 2009, was
approximately $24.0 billion, based upon the closing price
of $54.50 per share as reported by the New York Stock Exchange
on such date. On February 15, 2010, 446.8 million
shares of common stock were outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
Proxy
statement for the 2010 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
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 operations of Devon encompassing
oil and gas properties located in Canada.
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 discontinued operations of
Devon that encompass 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.
North American Onshore means our operations
encompassing oil and gas properties in the continental United
States and Canada.
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 operations of Devon
encompassing oil and gas properties in the Gulf of Mexico.
U.S. Onshore means the operations of Devon
encompassing oil and gas properties in the continental United
States.
INFORMATION
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, 2009 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 exploration, development and production of natural
gas and oil. Our oil and gas operations are concentrated in
various North American onshore areas in the United States and
Canada. We also have offshore operations that are situated
principally in the Gulf of Mexico and regions located offshore
Azerbaijan, Brazil and China.
To complement our upstream oil and gas operations, we have
marketing and midstream operations primarily in North America.
With these operations, we market gas, crude oil and NGLs. We
also construct and operate pipelines, storage and treating
facilities and natural gas processing plants. These midstream
facilities are used to transport oil, gas, and NGLs and process
natural gas.
We began operations in 1971 as a privately held company. We have
been publicly held since 1988, and our common stock is listed on
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
As an enterprise, we aspire to be the premier independent
natural gas and oil company in North America. To achieve this,
we continuously strive to optimize value for our shareholders by
growing reserves, production, earnings and cash flows, all on a
per share basis. We do this by:
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exercising capital discipline;
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investing in oil and gas properties with high operating margins;
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balancing our reserves and production mix between natural gas
and liquids;
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maintaining a low overall cost structure;
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improving performance through our marketing and midstream
operations; and
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preserving financial flexibility.
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Over the past decade, we captured an abundance of resources by
carrying out this strategy. We pioneered horizontal drilling in
the Barnett Shale and extended this technique to other natural
gas shale plays in the United States and Canada. We became
proficient with steam-assisted gravity drainage with our
Jackfish oil sands development in Alberta, Canada. We achieved
key oil discoveries with our drilling in the deepwater Gulf of
Mexico and offshore Brazil. We have more than tripled our proved
oil and gas reserves since 2000, and have also assembled an
extensive inventory of exploration assets representing
additional unproved resources.
Building off our past successes, in November 2009, we announced
plans to strategically reposition Devon as a high-growth, North
American onshore exploration and production company. As part of
this strategic repositioning, we plan to bring forward the value
of our offshore assets located in the Gulf of Mexico and
countries outside North America by divesting them.
This repositioning is driven by our desire to unlock and
accelerate the realization of the value underlying the deep
inventory of opportunities we have. We have assembled a valuable
portfolio of offshore assets, and we have a considerable
inventory of premier North American onshore assets. However, our
North American onshore assets have consistently provided us our
highest risk-adjusted investment returns. By selling our
offshore assets, we can more aggressively pursue the untapped
value of these North American onshore opportunities. Besides
reducing debt, the offshore divestiture proceeds are expected to
provide significant funds to redeploy into our prolific North
American onshore opportunities. With these added funds, we plan
to accelerate the growth and realization of the value of our
North American onshore assets.
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Presentation
of Discontinued Operations
As a result of the planned divestitures of our offshore assets,
all amounts in this document related to our International
operations are presented as discontinued. Therefore, financial
data and operational data, such as reserves, production, wells
and acreage, provided in this document exclude amounts related
to our International operations unless otherwise provided.
Even though we are also divesting our U.S. Offshore
operations, these properties do not qualify as discontinued
operations under accounting rules. As such, financial and
operational data provided in this document that pertain to our
continuing operations include amounts related to our
U.S. Offshore operations. Where appropriate, we have
presented amounts related to our U.S. Offshore assets
separate from those of our North American Onshore assets.
Development
of Business
Since our first issuance of common stock to the public in 1988,
we have executed strategies that have always been focused on
growth and value creation for our shareholders. We increased our
total proved reserves from 8 MMBoe at year-end 1987 to
2,733 MMBoe at year-end 2009. During this same time period,
we increased annual production from 1 MMBoe in 1987 to
233 MMBoe in 2009. Our expansion over this time period is
attributable to a focused mergers and acquisitions program
spanning a number of years, as well as active and successful
exploration and development programs in more recent years.
Additionally, our growth has provided meaningful value creation
for our shareholders. The growth statistics from 1987 to 2009
translate into annual per share growth rates of 11% for
production and 8% for reserves.
As a result of this growth, we have become one of the largest
independent oil and gas companies in North America. During 2009,
we continued to build off our past successes with a number of
key accomplishments, including those discussed below.
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Drilling Success We drilled 1,135 gross
wells with a 99% success rate. As a result of our success with
the drill-bit, we replaced approximately 213% of our 2009
production. We added 496 MMBoe of proved reserves during
the year with extensions, discoveries and performance revisions.
These reserve additions were more than double the 233 MMBoe
we produced during 2009. Besides increasing our proved reserves,
our drilling success was also the main driver of our 5%
production growth in 2009.
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Barnett Shale We drilled 336 wells in
the Barnett Shale field in north Texas in 2009, bringing our
total producing wells in the field to almost 4,200 at year end.
We exited 2009 with net Barnett Shale production at just over
one Bcf of natural gas equivalent per day. We are currently
running 16 operated drilling rigs in the Barnett and expect to
drill 370 wells in the field in 2010.
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Cana-Woodford Shale We drilled 47 successful
wells in the Cana-Woodford Shale in western Oklahoma in 2009. We
also increased our net production from this important new
shale-gas resource by nearly 500% to an average of 39 MMcf
of natural gas equivalent per day. We have increased our lease
position in the Cana-Woodford Shale to 118,000 net acres
and expect to drill approximately 85 wells in the field in
2010.
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Haynesville Shale We drilled eight
Haynesville Shale wells in the greater Carthage area of east
Texas in 2009. These wells have significantly de-risked our
110,000 net Haynesville Shale acres in the Carthage area.
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Jackfish In Canada, our 100-percent owned
Jackfish oil sands project in Alberta was operational throughout
2009. As measured by production per well and
steam-to-oil
ratio, Jackfish is one of Canadas most commercially
successful steam-assisted gravity drainage projects. In late
2009, Jackfishs gross production reached 33.7 MBbls
of oil per day. The addition of four more producing wells is
expected to push production to the facilitys capacity of
35 MBbls per day in early 2010.
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Construction continued throughout 2009 on a second phase of the
Jackfish project. Jackfish 2 is also sized to produce
35 MBbls of oil per day and will commence operations in
2011. We expect to file a regulatory application for a third
phase of the project in the third quarter of 2010.
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Brazil Offshore Brazil, we participated in
two significant deepwater discoveries in 2009. The
Devon-operated Itaipu exploratory discovery followed a
successful appraisal of the 2008 Wahoo discovery. Both Itaipu
and Wahoo are pre-salt prospects located in the Campos Basin.
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Financial
Information about Segments and Geographical Areas
Notes 20 and 22 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 or fixed-price contracts associated 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 and short-term
agreements at prices negotiated with third parties. Although
exact percentages vary daily, as of January 2010, approximately
81% of our oil production was sold under short-term contracts at
variable or market-sensitive prices. The remaining 19% of oil
production was sold under long-term, market-indexed contracts
that are subject to market pricing variations.
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 January 2010,
approximately 86% 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 13% 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.
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 January 2010, approximately 90% of
our NGL production was sold under short-term contracts at
variable or market-sensitive prices. The remaining 10% of NGL
production was sold under short-term, fixed-price contracts.
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 transport the combined product to the Edmonton
area for sale.
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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.
During 2009, 2008 and 2007, no purchaser accounted for over 10%
of our revenues.
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.
Public
Policy and Government Regulation
The oil and gas industry is subject to various types of
regulation throughout the world. Laws, rules, regulations and
other policy implementations affecting the oil and gas industry
have been pervasive and are under constant review for amendment
or expansion. Pursuant to public policy changes, 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
public policy changes affecting the oil and gas industry are
commonplace and because 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.
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Exploration
and Production Regulation
Our oil and gas operations are subject to various federal,
state, provincial, tribal, local and international laws and
regulations. These regulations relate to matters that include,
but are not limited to:
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acquisition of seismic data;
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location of wells;
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drilling and casing of wells;
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well production;
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spill prevention plans;
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emissions permitting;
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use, transportation, storage and disposal of fluids and
materials incidental to oil and gas operations;
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surface usage and the restoration of properties upon which wells
have been drilled;
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calculation and disbursement of royalty payments and production
taxes;
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plugging and abandoning of wells;
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transportation of production; and
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in international operations, minimum investments in the country
of operations.
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Our operations also are 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. natural gas and oil 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
also have established incentive programs such as royalty rate
reductions, royalty holidays, tax credits and fixed rate and
profit-sharing royalties 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.
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The provincial government of Alberta enacted a new royalty
regime effective January 1, 2009. The new regime links
royalties to price and production levels and applies to both new
and existing conventional oil and gas activities and oil sands
projects. This regime has generally reduced our proved reserves
and production in Alberta, as well as the related earnings and
cash flows. Similar effects have been experienced throughout the
oil and gas industry in Alberta. Acknowledging this impact on
the industry, the government of Alberta has announced a
competitiveness review to assess the impact to the industry as a
result of the royalty changes. However, we are uncertain whether
the current regime will be modified.
Pricing
and Marketing in Canada
Any oil or gas export to be made pursuant to an export contract
that exceeds a certain duration or a certain quantity requires
an exporter to obtain export authorizations 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.
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:
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assessing the environmental impact of seismic acquisition,
drilling or construction activities;
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the generation, storage, transportation and disposal of waste
materials;
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the emission of certain gases into the atmosphere;
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the monitoring, abandonment, reclamation and remediation of well
and other sites, including sites of former operations; and
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the development of emergency response and spill contingency
plans.
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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.
We consider the costs of environmental protection and safety and
health compliance necessary and manageable parts of our
business. We have been able to plan for and comply with
environmental, safety and health initiatives without materially
altering our operating strategy or incurring significant
unreimbursed expenditures. However, based on regulatory trends
and increasingly stringent laws, our capital expenditures and
operating expenses related to the protection of the environment
and safety and health compliance have increased over the years
and will likely continue to increase. 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.
10
Climate
Change
Policy makers in the United States are increasingly focusing on
whether the emissions of greenhouse gases, such as
carbon dioxide and methane, are contributing to the warming of
the Earths atmosphere and other climatic changes. However,
there is currently no settled scientific consensus on whether,
or the extent to which, human-derived greenhouse gas emissions
contribute to climatic change. As an oil and gas company, the
debate on climate change is relevant to our operations because
the equipment we use to explore for, develop, produce and
process oil and natural gas emits greenhouse gases.
Additionally, the combustion of carbon-based fuels, such as the
oil, gas and NGLs we sell, emits carbon dioxide and other
greenhouse gases. As a result, some believe that combustion of
carbon-based fuels contributes to climate change.
Despite the lack of a settled scientific consensus on
human-derived impacts on climate change, policy makers at both
the United States federal and state level have introduced
legislation and proposed new regulations that are designed to
quantify and limit the emission of greenhouse gases through
inventories and limitations on greenhouse gas emissions.
Legislative initiatives to date have focused on the development
of cap and trade programs. These programs generally
would cap overall greenhouse gas emissions on an economy-wide
basis and require major sources of greenhouse gas emissions or
major fuel producers to acquire and surrender emission
allowances. As a result of a gradually declining cap, the number
of government-issued allowances and allowances available for
trade would be reduced each year until the overall goal of
greenhouse gas emission reductions is achieved.
Because no final legislation or regulations limiting greenhouse
gas emissions have been enacted at this time, it is not possible
to estimate the costs or operational impacts we could experience
to comply with new legislative or regulatory developments.
Although we do not anticipate that we would be impacted to any
greater degree than other similar oil and gas companies, a
stringent greenhouse gas control program could increase our cost
of doing business and reduce demand for the oil and natural gas
that we sell. However, to the extent that any particular
greenhouse gas program directly or indirectly encourages the use
of natural gas, demand for the natural gas we sell could
increase.
The Kyoto Protocol was adopted by numerous countries in 1997 and
implemented in 2005. The Protocol requires reductions of certain
emissions of greenhouse gases. Although the United States has
not ratified the Protocol, certain countries in which we operate
have. Canada ratified the Protocol in April 2007 and released
its Regulatory Framework for Air Emissions. The Canadian
framework is a plan to implement mandatory reductions in
greenhouse gas emissions. The mandatory reductions on greenhouse
gas emissions will create additional costs for the Canadian oil
and gas industry, including us. Certain provinces in Canada also
have implemented or are currently implementing legislation and
regulations to report and reduce greenhouse gas emissions, which
also will carry 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 established 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 greenhouse gas
emission inventory. We last published our emission inventory on
January 2008. We will publish another emission inventory on or
before March 31, 2011 to comply with a reporting mandate
issued by the United States Environmental Protection Agency.
Additionally, we continue to explore energy efficiency measures
and greenhouse emission reduction opportunities. We also
continue to monitor legislative and regulatory climate change
developments, such as the proposals described above.
Employees
As of December 31, 2009, we had approximately
5,400 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.
11
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.
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.
12
Additional discussion of our policies and internal controls
related to estimating and recording reserves is described in
Item 2. Properties Preparation of
Reserves Estimates and Reserves Audits.
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 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
13
larger than ours. They also may have established strategic
long-term positions and relationships in areas 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.
International
Operations Have Uncertain Political, Economic and Other
Risks
Our operations outside North America are based primarily in
Azerbaijan, Brazil and China. As noted earlier in this report,
we are in the process of divesting our operations outside North
America. However, until we cease operating in these locations,
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.
Public
Policy, Which Includes Laws, Rules and Regulations, Can
Change
Our operations are subject to federal laws, rules 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
14
states, provinces, tribal and local governments. Pursuant to
public policy changes, 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 public policy 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 public policy 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 public
policy 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, 2009, our auction rate securities totaled
$115 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 2009, 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 problems in the global
credit markets, including but not limited to, U.S. subprime
mortgage defaults and writedowns by major financial institutions
due to deteriorating values of their asset portfolios. These and
other related factors have affected various sectors of the
financial markets and caused credit and liquidity issues. If
15
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.
Property
Overview
Our oil and gas operations are concentrated in various North
American onshore areas in the United States and Canada. We also
have offshore operations that are situated principally in the
Gulf of Mexico and regions located offshore Azerbaijan, Brazil
and China. As previously mentioned, we are in the process of
divesting our offshore assets. Our properties consist of
interests in developed and undeveloped oil and gas leases and
mineral acreage in these regions. 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 near
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.
16
The following sections provide additional details of our oil and
gas properties, including information about proved reserves,
production, wells, acreage and drilling activities.
Property
Profiles
The locations of our key North American Onshore properties are
presented on the following map.
17
The following table presents proved reserve information for our
key properties as of December 31, 2009, along with their
production volumes for the year 2009. Additional summary profile
information for our key properties is provided following the
table. Our key properties include those that currently have
significant proved reserves or production. These key properties
also include properties that do not have current significant
levels of proved reserves or production, but are expected be the
source of future significant growth in proved reserves and
production.
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Proved
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Proved
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Reserves
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Reserves
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Production
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Production
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(MMBoe)(1)
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%(2)
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(MMBoe)(1)
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%(2)
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U.S. Onshore
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Barnett Shale
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1,027
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37.6
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%
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69
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29.6
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%
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Carthage
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182
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6.7
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%
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14
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6.4
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%
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Permian Basin, Texas
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127
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4.6
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%
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9
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3.9
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%
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Washakie
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93
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3.4
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%
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7
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3.0
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%
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Cana-Woodford Shale
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73
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2.7
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%
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3
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1.0
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%
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Arkoma-Woodford Shale
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47
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1.7
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%
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5
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2.0
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%
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Groesbeck
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43
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1.6
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%
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6
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2.6
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%
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Haynesville Shale
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6
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0.2
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%
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1
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0.3
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%
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Other U.S. Onshore
|
|
|
280
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10.2
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%
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40
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17.1
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%
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Total U.S. Onshore
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1,878
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68.7
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%
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|
154
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65.9
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%
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U.S. Offshore
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92
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3.4
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%
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13
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5.7
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%
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Total U.S.
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1,970
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72.1
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%
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|
167
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71.6
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%
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Canada
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Jackfish
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403
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14.7
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%
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|
8
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3.4
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%
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Northwest
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|
|
117
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|
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|
4.3
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%
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|
16
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|
|
|
7.3
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%
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Lloydminster
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|
|
81
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|
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|
3.0
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%
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|
16
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|
|
|
6.7
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%
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Deep Basin
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|
59
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|
2.2
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%
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|
12
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|
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5.0
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%
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Horn River Basin
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|
2
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|
|
|
|
|
|
|
|
|
|
|
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Other Canada
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|
|
101
|
|
|
|
3.7
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%
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|
|
14
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|
|
|
6.0
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%
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|
|
|
|
|
|
|
|
|
|
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|
|
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Total Canada
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|
763
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27.9
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%
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|
|
66
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|
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28.4
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%
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|
|
|
|
|
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|
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North America
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|
|
2,733
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|
|
100.0
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%
|
|
|
233
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|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
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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 relationship of gas and oil
prices. NGL reserves and production are converted to Boe on a
one-to-one
basis with oil. |
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(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
663,000 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 89%. We drilled
336 gross wells in 2009 and plan to drill approximately
370 gross wells in 2010.
18
Carthage The Carthage area in east Texas
includes primarily Harrison, Marion, Panola and Shelby counties.
Our average working interest is about 86% and we hold
approximately 218,000 net acres. Our Carthage area wells
produce primarily natural gas and NGLs from conventional
reservoirs. We drilled 39 gross wells in 2009 and plan to
drill approximately 30 gross wells in 2010.
Permian Basin, Texas Our oil and gas
properties in the Permian Basin of west Texas comprise
approximately 850,000 net acres located across several
counties in west Texas. These properties produce both oil and
gas from conventional reservoirs. Our average working interest
in these properties is about 40%. In 2009, we drilled
80 gross wells and plan to drill approximately
220 gross wells in 2010.
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
2009, we drilled 94 gross wells and plan to drill
approximately 115 gross wells in 2010.
Cana-Woodford Shale The Cana-Woodford Shale
is located in Canadian, Blaine and Caddo counties in western
Oklahoma. Our average working interest is approximately 46% and
we hold approximately 117,000 net acres. Our Cana-Woodford
Shale properties produce natural gas and NGLs from a
non-conventional reservoir. We drilled 47 gross wells in
2009 and plan to drill approximately 85 gross wells in
2010. To support our growing production in the Cana-Woodford
Shale, we are building a 200 MMcf per day natural gas
processing facility. We expect to complete this facility in
early 2011.
Arkoma-Woodford Shale Our Arkoma-Woodford
Shale properties in southeastern Oklahoma produce natural gas
and NGLs from a non-conventional reservoir. Our 58,000 net
acres are concentrated in Coal and Hughes counties, and we have
an average working interest of about 32%. In 2009, we drilled
61 gross wells in this area and plan to drill approximately
85 gross wells in 2010.
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 132,000 net acres of land. The Groesbeck
wells produce primarily natural gas from conventional
reservoirs. In 2009, we drilled 13 gross wells and plan to
drill approximately 10 gross wells in 2010.
Haynesville Shale Our Haynesville Shale
acreage spans across east Texas and north Louisiana with an
average working interest of 92%. To date, our drilling activity
has been focused on de-risking the 157,000 acres located in
Panola, Shelby and San Augustine counties in east Texas. We
drilled 8 gross wells in 2009 and plan to drill
approximately 30 gross wells in 2010.
Canada
Jackfish Jackfish is our 100%-owned thermal
heavy oil project in the non-conventional oil sands of east
central Alberta. We are employing steam-assisted gravity
drainage at Jackfish. In late 2009, Jackfishs gross
production reached 33.7 MBbls of oil per day. Gross peak
production is expected to be 35 MBbls per day with a flat
production profile for greater than 20 years. We are
currently constructing the second phase of Jackfish and
evaluating the potential for a third phase. The second and third
phases of Jackfish are each expected to also eventually produce
35 MBbls per day of heavy oil production.
Northwest The Northwest region includes
acreage within west central Alberta and northeast British
Columbia. We hold approximately 1.9 million net acres in
the region, which produces primarily natural gas and NGLs from
conventional reservoirs. Our average working interest in the
area is approximately 73%. In 2009, we drilled 36 gross
wells and plan to drill approximately 55 gross wells in
2010.
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 2009, we drilled
239 gross wells and plan to drill approximately
140 gross wells in 2010.
Deep Basin Our properties in Canadas
Deep Basin include portions of west central Alberta and east
central British Columbia. We hold approximately 570,000 net
acres in the Deep Basin. The area produces
19
primarily natural gas and natural gas liquids from conventional
reservoirs. Our average working interest in the Deep Basin is
45%. In 2009, we drilled 30 gross wells and plan to drill
approximately 35 gross wells in 2010.
Horn River Basin The Horn River Basin,
located in northeast British Columbia, is a non-conventional
reservoir targeting the Devonian Shale. Our leases include
approximately 170,000 net acres with a 100% working
interest. We drilled 2 gross wells in 2009. During 2010, we
plan to drill 11 gross wells, consisting of 7 horizontal
wells and 4 vertical stratigraphic-test wells.
Preparation
of Reserves Estimates and Reserves Audits
Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically
producible from known reservoirs under existing economic
conditions, operating methods and government regulations. To be
considered proved, oil and gas reserves must be economically
producible before contracts providing the right to operate
expire, unless evidence indicates that renewal is reasonably
certain. Also, the project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it
will commence the project within a reasonable time.
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). These same policies also require that
reserve estimates be made by professionally qualified reserves
estimators (Qualified Estimators), as defined by the
Society of Petroleum Engineers standards.
The Group, which is led by Devons Director of Reserves and
Economics, is responsible for the internal review and
certification of reserves estimates. We ensure the Groups
Director and key members of the Group have appropriate technical
qualifications to oversee the preparation of reserves estimates.
Such qualifications include any or all of the following:
|
|
|
|
|
an undergraduate degree in petroleum engineering from an
accredited university, or equivalent;
|
|
|
|
a petroleum engineering license, or similar certification;
|
|
|
|
memberships in oil and gas industry or trade groups; and
|
|
|
|
relevant experience estimating reserves.
|
The current Director of the Group and the Groups key
members all have the qualifications listed above. Additionally,
the Group reports independently of any of our operating
divisions. The Groups Director reports to our Senior Vice
President of Strategic Development, who 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. The Group also ensures our
Qualified Estimators obtain continuing education related to the
fundamentals of SEC proved reserves assignments.
The Group also oversees audits and reserves estimates performed
by third-party consulting firms. During 2009, we engaged three
such firms to both prepare and audit a significant portion of
our proved reserves. Ryder Scott Company, L.P. prepared the 2009
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 2009 reserve
estimates for 93% of our domestic onshore properties. AJM
Petroleum Consultants audited 91% of our Canadian reserves.
20
Set forth below is a summary of the North American reserves that
were evaluated, either by preparation or audit, by independent
petroleum consultants for each of the years ended 2009, 2008 and
2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Prepared
|
|
|
Audited
|
|
|
Prepared
|
|
|
Audited
|
|
|
Prepared
|
|
|
Audited
|
|
|
U.S. Onshore
|
|
|
|
|
|
|
93
|
%
|
|
|
|
|
|
|
92
|
%
|
|
|
|
|
|
|
88
|
%
|
U.S. Offshore
|
|
|
100
|
%
|
|
|
|
|
|
|
100
|
%
|
|
|
|
|
|
|
100
|
%
|
|
|
|
|
Total U.S.
|
|
|
5
|
%
|
|
|
89
|
%
|
|
|
5
|
%
|
|
|
87
|
%
|
|
|
6
|
%
|
|
|
82
|
%
|
Canada
|
|
|
|
|
|
|
91
|
%
|
|
|
|
|
|
|
78
|
%
|
|
|
34
|
%
|
|
|
51
|
%
|
Total North America
|
|
|
3
|
%
|
|
|
89
|
%
|
|
|
4
|
%
|
|
|
85
|
%
|
|
|
15
|
%
|
|
|
73
|
%
|
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 that 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:
|
|
|
|
|
perform an annual review and evaluation of our consolidated oil,
gas and NGL reserves;
|
|
|
|
verify the integrity of our reserves evaluation and reporting
system;
|
|
|
|
evaluate, prepare and disclose our compliance with legal and
regulatory requirements related to our oil, gas and NGL reserves;
|
|
|
|
investigate and verify the qualifications and independence of
our independent engineering consultants;
|
|
|
|
monitor the performance of our independent engineering
consultants; and
|
|
|
|
monitor and evaluate our business practices and ethical
standards in relation to the preparation and disclosure of
reserves.
|
21
Proved
Oil, Natural Gas and NGL Reserves
The following table presents our estimated proved reserves by
continent and for each significant country as of
December 31, 2009. These estimates correspond with the
method used in presenting the Supplemental Information on
Oil and Gas Operations in Note 22 to our consolidated
financial statements included in this report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Gas Liquids
|
|
|
Total(1)
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBoe)
|
|
|
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
|
139
|
|
|
|
8,127
|
|
|
|
385
|
|
|
|
1,878
|
|
U.S. Offshore
|
|
|
33
|
|
|
|
342
|
|
|
|
2
|
|
|
|
92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
172
|
|
|
|
8,469
|
|
|
|
387
|
|
|
|
1,970
|
|
Canada
|
|
|
514
|
|
|
|
1,288
|
|
|
|
34
|
|
|
|
763
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
686
|
|
|
|
9,757
|
|
|
|
421
|
|
|
|
2,733
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
|
119
|
|
|
|
6,447
|
|
|
|
293
|
|
|
|
1,486
|
|
U.S. Offshore
|
|
|
21
|
|
|
|
185
|
|
|
|
1
|
|
|
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
140
|
|
|
|
6,632
|
|
|
|
294
|
|
|
|
1,539
|
|
Canada
|
|
|
149
|
|
|
|
1,213
|
|
|
|
32
|
|
|
|
383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
289
|
|
|
|
7,845
|
|
|
|
326
|
|
|
|
1,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
|
20
|
|
|
|
1,680
|
|
|
|
92
|
|
|
|
392
|
|
U.S. Offshore
|
|
|
12
|
|
|
|
157
|
|
|
|
1
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
32
|
|
|
|
1,837
|
|
|
|
93
|
|
|
|
431
|
|
Canada
|
|
|
365
|
|
|
|
75
|
|
|
|
2
|
|
|
|
380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
397
|
|
|
|
1,912
|
|
|
|
95
|
|
|
|
811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. This rate is not necessarily indicative of the
relationship of natural gas and oil prices. Natural gas liquids
reserves are converted to Boe on a
one-to-one
basis with oil. |
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 2009 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.
22
Proved
Developed Reserves
As presented in the previous table, we had 1,922 MMBoe of
proved developed reserves at December 31, 2009. 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, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Gas Liquids
|
|
|
Total(1)
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBoe)
|
|
|
Proved Developed Producing Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
|
111
|
|
|
|
5,859
|
|
|
|
265
|
|
|
|
1,354
|
|
U.S. Offshore
|
|
|
12
|
|
|
|
137
|
|
|
|
1
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
123
|
|
|
|
5,996
|
|
|
|
266
|
|
|
|
1,389
|
|
Canada
|
|
|
137
|
|
|
|
1,075
|
|
|
|
28
|
|
|
|
344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
260
|
|
|
|
7,071
|
|
|
|
294
|
|
|
|
1,733
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Non-Producing Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
|
8
|
|
|
|
588
|
|
|
|
28
|
|
|
|
132
|
|
U.S. Offshore
|
|
|
9
|
|
|
|
48
|
|
|
|
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
17
|
|
|
|
636
|
|
|
|
28
|
|
|
|
150
|
|
Canada
|
|
|
12
|
|
|
|
138
|
|
|
|
4
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
29
|
|
|
|
774
|
|
|
|
32
|
|
|
|
189
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. This rate is not necessarily indicative of the
relationship of natural gas and oil prices. Natural gas liquids
reserves are converted to Boe on a
one-to-one
basis with oil. |
Proved
Undeveloped Reserves
The following table presents the changes in our total proved
undeveloped reserves during 2009 (in MMBoe).
|
|
|
|
|
Proved undeveloped reserves as of December 31, 2008
|
|
|
424
|
|
Revisions due to prices
|
|
|
174
|
|
Revisions other than price
|
|
|
(22
|
)
|
Extensions and discoveries
|
|
|
316
|
|
Conversion to proved developed reserves
|
|
|
(81
|
)
|
|
|
|
|
|
Proved undeveloped reserves as of December 31, 2009
|
|
|
811
|
|
|
|
|
|
|
During 2009, our proved undeveloped reserves increased 91%. A
large contributor to the increase was our 2009 drilling
activities, which increased our proved undeveloped reserves
316 MMBoe. Also as a result of 2009 drilling activities, we
converted 81 MMBoe, or 19%, of the 2008 proved undeveloped
reserves to proved developed reserves.
Our proved undeveloped reserves at the end of 2009 largely
relate to our operations at Jackfish and the Barnett Shale.
Additionally, the 2009 positive revisions due to prices largely
related to Jackfish. At the end of 2008, none of our Jackfish
reserves were classified as proved due to low oil prices.
However, as oil prices rebounded during 2009, our Jackfish
reserves, including the reserves that were undeveloped at the
end of 2008, once again became economic and were classified as
proved at the end of 2009. The positive revision related to
Jackfish reserves was partially offset by decreases in proved
undeveloped gas reserves related to certain of our North
American Onshore properties.
23
At the end of 2009, approximately 1% of our proved reserves had
been classified as proved undeveloped for more than five years.
The majority of such reserves relate to our deepwater Gulf of
Mexico operations where sanctioned development projects often
take longer than five years to complete.
Proved
Reserves Cash Flows
The following table presents estimated cash flow information
related to our December 31, 2009 estimated proved reserves.
Similar to reserves, the cash flow estimates correspond with the
method used in presenting the Supplemental Information on
Oil and Gas Operations in Note 22 to our consolidated
financial statements included in this report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
Proved
|
|
|
Proved
|
|
|
|
Proved
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
|
Reserves
|
|
|
Reserves
|
|
|
Reserves
|
|
|
|
(In millions)
|
|
|
Pre-Tax Future Net Revenue(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
15,573
|
|
|
$
|
13,381
|
|
|
$
|
2,192
|
|
Canada
|
|
|
14,463
|
|
|
|
6,127
|
|
|
|
8,336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
$
|
30,036
|
|
|
$
|
19,508
|
|
|
$
|
10,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-Tax 10% Present Value(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
7,630
|
|
|
$
|
7,452
|
|
|
$
|
178
|
|
Canada
|
|
|
7,243
|
|
|
|
4,210
|
|
|
|
3,033
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
$
|
14,873
|
|
|
$
|
11,662
|
|
|
$
|
3,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash
Flows(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
5,880
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
5,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
$
|
11,403
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
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 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. |
|
|
|
Future net revenues are calculated using prices that represent
the average of the
first-day-of-the-month
price for the
12-month
period prior to December 31, 2009. 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 $47.80
per Bbl of oil, $3.12 per Mcf of gas and $22.78 per Bbl of NGLs.
Costs included in future net revenues are determined in a
similar manner. 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, 2009. 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. |
|
|
|
The present value of after-tax future net revenues discounted at
10% per annum (standardized measure) was
$11.4 billion at the end of 2009. Included as part of
standardized measure were discounted future income taxes of
$3.4 billion. Excluding these taxes, the present value of
our pre-tax future net revenue (pre-tax 10% present
value) was $14.8 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, |
24
|
|
|
|
|
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. |
|
(2) |
|
See Note 22 to the consolidated financial statements
included in Item 8. Financial Statements and
Supplementary Data. |
Production,
Production Prices and Production Costs
The following tables present our production and average sales
prices by continent and for each significant field and country
for the past three years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Gas Liquids
|
|
|
Total(1)
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBoe)
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
|
|
|
|
|
331
|
|
|
|
13
|
|
|
|
69
|
|
Other United States fields
|
|
|
17
|
|
|
|
412
|
|
|
|
13
|
|
|
|
98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
17
|
|
|
|
743
|
|
|
|
26
|
|
|
|
167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jackfish
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
Other Canada fields
|
|
|
17
|
|
|
|
223
|
|
|
|
4
|
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Canada
|
|
|
25
|
|
|
|
223
|
|
|
|
4
|
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
42
|
|
|
|
966
|
|
|
|
30
|
|
|
|
233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Gas Liquids
|
|
|
Combined(1)
|
|
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Boe)
|
|
|
Production Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
$
|
58.78
|
|
|
$
|
2.99
|
|
|
$
|
22.36
|
|
|
$
|
19.08
|
|
Total United States
|
|
$
|
57.56
|
|
|
$
|
3.20
|
|
|
$
|
23.51
|
|
|
$
|
23.71
|
|
Jackfish
|
|
$
|
41.07
|
|
|
|
|
|
|
|
|
|
|
$
|
41.07
|
|
Total Canada
|
|
$
|
47.35
|
|
|
$
|
3.66
|
|
|
$
|
33.09
|
|
|
$
|
32.29
|
|
Total North America
|
|
$
|
51.39
|
|
|
$
|
3.31
|
|
|
$
|
24.71
|
|
|
$
|
26.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Gas Liquids
|
|
|
Total(1)
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBoe)
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
|
|
|
|
|
321
|
|
|
|
12
|
|
|
|
66
|
|
Other United States fields
|
|
|
17
|
|
|
|
405
|
|
|
|
12
|
|
|
|
96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
17
|
|
|
|
726
|
|
|
|
24
|
|
|
|
162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jackfish
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
Other Canada fields
|
|
|
18
|
|
|
|
212
|
|
|
|
4
|
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Canada
|
|
|
22
|
|
|
|
212
|
|
|
|
4
|
|
|
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
39
|
|
|
|
938
|
|
|
|
28
|
|
|
|
223
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Gas Liquids
|
|
|
Combined(1)
|
|
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Boe)
|
|
|
Production Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
$
|
97.23
|
|
|
$
|
7.38
|
|
|
$
|
39.34
|
|
|
$
|
43.71
|
|
Total United States
|
|
$
|
98.83
|
|
|
$
|
7.59
|
|
|
$
|
41.21
|
|
|
$
|
50.55
|
|
Jackfish
|
|
$
|
50.67
|
|
|
|
|
|
|
|
|
|
|
$
|
50.67
|
|
Total Canada
|
|
$
|
71.04
|
|
|
$
|
8.17
|
|
|
$
|
61.45
|
|
|
$
|
57.65
|
|
Total North America
|
|
$
|
83.35
|
|
|
$
|
7.73
|
|
|
$
|
44.08
|
|
|
$
|
52.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Gas Liquids
|
|
|
Total(1)
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBoe)
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
|
|
|
|
|
238
|
|
|
|
10
|
|
|
|
50
|
|
Other United States fields
|
|
|
19
|
|
|
|
397
|
|
|
|
12
|
|
|
|
96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
19
|
|
|
|
635
|
|
|
|
22
|
|
|
|
146
|
|
Total Canada
|
|
|
16
|
|
|
|
227
|
|
|
|
4
|
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
35
|
|
|
|
862
|
|
|
|
26
|
|
|
|
204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Gas Liquids
|
|
|
Combined(1)
|
|
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Boe)
|
|
|
Production Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
$
|
70.61
|
|
|
$
|
5.63
|
|
|
$
|
34.68
|
|
|
$
|
34.28
|
|
Total United States
|
|
$
|
69.23
|
|
|
$
|
5.87
|
|
|
$
|
36.11
|
|
|
$
|
39.77
|
|
Total Canada
|
|
$
|
49.80
|
|
|
$
|
6.24
|
|
|
$
|
46.07
|
|
|
$
|
41.51
|
|
Total North America
|
|
$
|
60.30
|
|
|
$
|
5.97
|
|
|
$
|
37.76
|
|
|
$
|
40.26
|
|
|
|
|
(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. This rate is not necessarily indicative of the
relationship of natural gas and oil prices. Natural gas liquids
reserves are converted to Boe on a
one-to-one
basis with oil. |
The following table presents our production cost per Boe by
continent and for each significant field and country for the
past three years. Production costs do not include ad valorem or
severance taxes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Barnett Shale
|
|
$
|
3.96
|
|
|
$
|
4.34
|
|
|
$
|
3.85
|
|
Total United States
|
|
$
|
5.97
|
|
|
$
|
6.62
|
|
|
$
|
6.19
|
|
Jackfish
|
|
$
|
12.75
|
|
|
$
|
28.93
|
|
|
|
|
|
Total Canada
|
|
$
|
10.15
|
|
|
$
|
12.74
|
|
|
$
|
10.80
|
|
Total North America
|
|
$
|
7.16
|
|
|
$
|
8.29
|
|
|
$
|
7.50
|
|
26
Drilling
Activities and Results
The following tables summarize our development and exploratory
drilling results for the past three years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
Development Wells(1)
|
|
|
Exploratory Wells(1)
|
|
|
Total Wells(1)
|
|
|
|
Productive
|
|
|
Dry
|
|
|
Productive
|
|
|
Dry
|
|
|
Productive
|
|
|
Dry
|
|
|
U.S. Onshore
|
|
|
506.5
|
|
|
|
3.0
|
|
|
|
6.8
|
|
|
|
1.5
|
|
|
|
513.3
|
|
|
|
4.5
|
|
U.S. Offshore
|
|
|
1.5
|
|
|
|
0.8
|
|
|
|
|
|
|
|
0.5
|
|
|
|
1.5
|
|
|
|
1.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
508.0
|
|
|
|
3.8
|
|
|
|
6.8
|
|
|
|
2.0
|
|
|
|
514.8
|
|
|
|
5.8
|
|
Canada
|
|
|
307.2
|
|
|
|
|
|
|
|
28.2
|
|
|
|
|
|
|
|
335.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
815.2
|
|
|
|
3.8
|
|
|
|
35.0
|
|
|
|
2.0
|
|
|
|
850.2
|
|
|
|
5.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
Development
|
|
|
|
|
|
|
|
|
|
Wells(1)
|
|
|
Exploratory Wells(1)
|
|
|
Total Wells(1)
|
|
|
|
Productive
|
|
|
Dry
|
|
|
Productive
|
|
|
Dry
|
|
|
Productive
|
|
|
Dry
|
|
|
U.S. Onshore
|
|
|
1,024.0
|
|
|
|
17.5
|
|
|
|
12.8
|
|
|
|
2.0
|
|
|
|
1,036.8
|
|
|
|
19.5
|
|
U.S. Offshore
|
|
|
9.0
|
|
|
|
1.0
|
|
|
|
0.8
|
|
|
|
1.8
|
|
|
|
9.8
|
|
|
|
2.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
1,033.0
|
|
|
|
18.5
|
|
|
|
13.6
|
|
|
|
3.8
|
|
|
|
1,046.6
|
|
|
|
22.3
|
|
Canada
|
|
|
528.9
|
|
|
|
3.2
|
|
|
|
50.1
|
|
|
|
3.3
|
|
|
|
579.0
|
|
|
|
6.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
1,561.9
|
|
|
|
21.7
|
|
|
|
63.7
|
|
|
|
7.1
|
|
|
|
1,625.6
|
|
|
|
28.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Development
|
|
|
|
|
|
|
|
|
|
Wells(1)
|
|
|
Exploratory Wells(1)
|
|
|
Total Wells(1)
|
|
|
|
Productive
|
|
|
Dry
|
|
|
Productive
|
|
|
Dry
|
|
|
Productive
|
|
|
Dry
|
|
|
U.S. Onshore
|
|
|
974.4
|
|
|
|
21.1
|
|
|
|
10.1
|
|
|
|
4.0
|
|
|
|
984.5
|
|
|
|
25.1
|
|
U.S. Offshore
|
|
|
3.7
|
|
|
|
|
|
|
|
1.5
|
|
|
|
0.2
|
|
|
|
5.2
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
978.1
|
|
|
|
21.1
|
|
|
|
11.6
|
|
|
|
4.2
|
|
|
|
989.7
|
|
|
|
25.3
|
|
Canada
|
|
|
531.2
|
|
|
|
|
|
|
|
83.3
|
|
|
|
1.5
|
|
|
|
614.5
|
|
|
|
1.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
1,509.3
|
|
|
|
21.1
|
|
|
|
94.9
|
|
|
|
5.7
|
|
|
|
1,604.2
|
|
|
|
26.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
These well counts represent net wells completed during each
year. Net wells are gross wells multiplied by our fractional
working interests on the well. |
The following table presents the results, as of February 1,
2010, of our wells that were in progress as of December 31,
2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
Dry
|
|
|
Still in Progress
|
|
|
Total
|
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
U.S. Onshore
|
|
|
13
|
|
|
|
9.1
|
|
|
|
|
|
|
|
|
|
|
|
46
|
|
|
|
33.2
|
|
|
|
59
|
|
|
|
42.3
|
|
U.S. Offshore
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
1.5
|
|
|
|
3
|
|
|
|
1.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
13
|
|
|
|
9.1
|
|
|
|
|
|
|
|
|
|
|
|
49
|
|
|
|
34.7
|
|
|
|
62
|
|
|
|
43.8
|
|
Canada
|
|
|
18
|
|
|
|
13.7
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
2.5
|
|
|
|
21
|
|
|
|
16.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
31
|
|
|
|
22.8
|
|
|
|
|
|
|
|
|
|
|
|
52
|
|
|
|
37.2
|
|
|
|
83
|
|
|
|
60.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gross wells are the sum of all wells in which we own an interest. |
27
|
|
|
(2) |
|
Net wells are gross wells multiplied by our fractional working
interests on the well. |
Well
Statistics
The following table sets forth our producing wells as of
December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Wells
|
|
|
Natural Gas Wells
|
|
|
Total Wells
|
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
U.S. Onshore
|
|
|
8,301
|
|
|
|
2,901
|
|
|
|
19,792
|
|
|
|
13,442
|
|
|
|
28,093
|
|
|
|
16,343
|
|
U.S. Offshore
|
|
|
359
|
|
|
|
284
|
|
|
|
204
|
|
|
|
138
|
|
|
|
563
|
|
|
|
422
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
8,660
|
|
|
|
3,185
|
|
|
|
19,996
|
|
|
|
13,580
|
|
|
|
28,656
|
|
|
|
16,765
|
|
Canada
|
|
|
4,830
|
|
|
|
3,661
|
|
|
|
5,560
|
|
|
|
3,241
|
|
|
|
10,390
|
|
|
|
6,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
13,490
|
|
|
|
6,846
|
|
|
|
25,556
|
|
|
|
16,821
|
|
|
|
39,046
|
|
|
|
23,667
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 on the well. |
Acreage
Statistics
The following table sets forth our developed and undeveloped oil
and gas lease and mineral acreage as of December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
Gross(1)
|
|
|
Net(2)
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
|
3,357
|
|
|
|
2,268
|
|
|
|
6,064
|
|
|
|
3,318
|
|
|
|
9,421
|
|
|
|
5,586
|
|
U.S. Offshore
|
|
|
258
|
|
|
|
139
|
|
|
|
1,809
|
|
|
|
1,029
|
|
|
|
2,067
|
|
|
|
1,168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
3,615
|
|
|
|
2,407
|
|
|
|
7,873
|
|
|
|
4,347
|
|
|
|
11,488
|
|
|
|
6,754
|
|
Canada
|
|
|
3,630
|
|
|
|
2,253
|
|
|
|
7,688
|
|
|
|
5,088
|
|
|
|
11,318
|
|
|
|
7,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
7,245
|
|
|
|
4,660
|
|
|
|
15,561
|
|
|
|
9,435
|
|
|
|
22,806
|
|
|
|
14,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gross acres are the sum of all acres in which we own an interest. |
|
(2) |
|
Net acres are gross acres multiplied by our fractional working
interests on the acreage. |
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 24,221 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.
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.
28
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.
|
|
Item 3.
|
Legal
Proceedings
|
We are involved in various routine legal proceedings incidental
to our business. However, to our knowledge as of the date of
this report, there were no 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 2009.
29
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 15, 2010, there were 13,740
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 2009 and 2008. Also,
included are the quarterly dividends per share paid during 2009
and 2008. 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Range of Common Stock
|
|
|
Dividends
|
|
|
|
High
|
|
|
Low
|
|
|
Per Share
|
|
|
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended March 31, 2009
|
|
$
|
73.11
|
|
|
$
|
38.55
|
|
|
$
|
0.16
|
|
Quarter Ended June 30, 2009
|
|
$
|
67.40
|
|
|
$
|
43.35
|
|
|
$
|
0.16
|
|
Quarter Ended September 30, 2009
|
|
$
|
72.91
|
|
|
$
|
48.74
|
|
|
$
|
0.16
|
|
Quarter Ended December 31, 2009
|
|
$
|
75.05
|
|
|
$
|
62.60
|
|
|
$
|
0.16
|
|
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended March 31, 2008
|
|
$
|
108.13
|
|
|
$
|
74.56
|
|
|
$
|
0.16
|
|
Quarter Ended June 30, 2008
|
|
$
|
127.16
|
|
|
$
|
101.31
|
|
|
$
|
0.16
|
|
Quarter Ended September 30, 2008
|
|
$
|
127.43
|
|
|
$
|
82.10
|
|
|
$
|
0.16
|
|
Quarter Ended December 31, 2008
|
|
$
|
91.69
|
|
|
$
|
54.40
|
|
|
$
|
0.16
|
|
30
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, 2004 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
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.
Issuer
Purchases of Equity Securities
During 2009, we had two programs in effect in which our Board of
Directors had authorized the repurchase of up to
54.8 million shares of our common stock. We did not
repurchase any shares under these programs in 2009. These plans
expired on December 31, 2009.
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 2009 annual
certification of our Chief Executive Officer confirming that we
have complied with the New York Stock Exchange corporate
governance listing standards.
31
|
|
Item 6.
|
Selected
Financial Data
|
The following selected financial information (not covered by the
report of our 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,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions, except per share data, ratios,
|
|
|
|
prices and per Boe amounts)
|
|
|
Operating Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
8,015
|
|
|
$
|
13,858
|
|
|
$
|
9,975
|
|
|
$
|
9,143
|
|
|
$
|
9,630
|
|
Total expenses and other income, net(1)
|
|
|
12,541
|
|
|
|
18,018
|
|
|
|
6,648
|
|
|
|
5,957
|
|
|
|
5,477
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations before income taxes
|
|
|
(4,526
|
)
|
|
|
(4,160
|
)
|
|
|
3,327
|
|
|
|
3,186
|
|
|
|
4,153
|
|
Total income tax (benefit) expense
|
|
|
(1,773
|
)
|
|
|
(1,121
|
)
|
|
|
842
|
|
|
|
870
|
|
|
|
1,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
|
(2,753
|
)
|
|
|
(3,039
|
)
|
|
|
2,485
|
|
|
|
2,316
|
|
|
|
2,740
|
|
Earnings from discontinued operations(1)
|
|
|
274
|
|
|
|
891
|
|
|
|
1,121
|
|
|
|
530
|
|
|
|
190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(2,479
|
)
|
|
$
|
(2,148
|
)
|
|
$
|
3,606
|
|
|
$
|
2,846
|
|
|
$
|
2,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings applicable to common stockholders
|
|
$
|
(2,479
|
)
|
|
$
|
(2,153
|
)
|
|
$
|
3,596
|
|
|
$
|
2,836
|
|
|
$
|
2,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
$
|
(6.20
|
)
|
|
$
|
(6.86
|
)
|
|
$
|
5.56
|
|
|
$
|
5.22
|
|
|
$
|
5.96
|
|
Earnings from discontinued operations
|
|
|
0.62
|
|
|
|
2.01
|
|
|
|
2.52
|
|
|
|
1.20
|
|
|
|
0.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(5.58
|
)
|
|
$
|
(4.85
|
)
|
|
$
|
8.08
|
|
|
$
|
6.42
|
|
|
$
|
6.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net (loss) earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
$
|
(6.20
|
)
|
|
$
|
(6.86
|
)
|
|
$
|
5.50
|
|
|
$
|
5.15
|
|
|
$
|
5.86
|
|
Earnings from discontinued operations
|
|
|
0.62
|
|
|
|
2.01
|
|
|
|
2.50
|
|
|
|
1.19
|
|
|
|
0.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(5.58
|
)
|
|
$
|
(4.85
|
)
|
|
$
|
8.00
|
|
|
$
|
6.34
|
|
|
$
|
6.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per common share
|
|
$
|
0.64
|
|
|
$
|
0.64
|
|
|
$
|
0.56
|
|
|
$
|
0.45
|
|
|
$
|
0.30
|
|
Ratio of earnings to fixed charges(1)(2)
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
6.97
|
|
|
|
7.11
|
|
|
|
7.67
|
|
Ratio of earnings to combined fixed charges and preferred stock
dividends(1)(2)
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
6.78
|
|
|
|
6.91
|
|
|
|
7.49
|
|
Cash Flow Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
4,737
|
|
|
$
|
9,408
|
|
|
$
|
6,651
|
|
|
$
|
5,993
|
|
|
$
|
5,612
|
|
Net cash used in investing activities
|
|
$
|
(5,354
|
)
|
|
$
|
(6,873
|
)
|
|
$
|
(5,714
|
)
|
|
$
|
(7,449
|
)
|
|
$
|
(1,652
|
)
|
Net cash provided by (used in) financing activities
|
|
$
|
1,201
|
|
|
$
|
(3,408
|
)
|
|
$
|
(371
|
)
|
|
$
|
593
|
|
|
$
|
(3,543
|
)
|
Production, Price and Other Data(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
42
|
|
|
|
39
|
|
|
|
35
|
|
|
|
32
|
|
|
|
38
|
|
Gas (Bcf)
|
|
|
966
|
|
|
|
938
|
|
|
|
862
|
|
|
|
807
|
|
|
|
816
|
|
NGLs (MMBbls)
|
|
|
30
|
|
|
|
28
|
|
|
|
26
|
|
|
|
23
|
|
|
|
24
|
|
Total (MMBoe)(4)
|
|
|
233
|
|
|
|
223
|
|
|
|
204
|
|
|
|
190
|
|
|
|
198
|
|
Realized prices without hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
51.39
|
|
|
$
|
83.35
|
|
|
$
|
60.30
|
|
|
$
|
56.18
|
|
|
$
|
47.90
|
|
Gas (per Mcf)
|
|
$
|
3.31
|
|
|
$
|
7.73
|
|
|
$
|
5.97
|
|
|
$
|
6.03
|
|
|
$
|
7.08
|
|
NGLs (per Bbl)
|
|
$
|
24.71
|
|
|
$
|
44.08
|
|
|
$
|
37.76
|
|
|
$
|
32.10
|
|
|
$
|
29.05
|
|
Combined (per Boe)(4)
|
|
$
|
26.15
|
|
|
$
|
52.49
|
|
|
$
|
40.26
|
|
|
$
|
39.09
|
|
|
$
|
41.96
|
|
Lease operating expenses per Boe(4)
|
|
$
|
7.16
|
|
|
$
|
8.29
|
|
|
$
|
7.50
|
|
|
$
|
6.48
|
|
|
$
|
5.60
|
|
Depreciation, depletion and amortization of oil and gas
properties per Boe(4)
|
|
$
|
7.86
|
|
|
$
|
13.20
|
|
|
$
|
11.81
|
|
|
$
|
10.28
|
|
|
$
|
8.62
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets(1)
|
|
$
|
29,686
|
|
|
$
|
31,908
|
|
|
$
|
41,456
|
|
|
$
|
35,063
|
|
|
$
|
30,273
|
|
Long-term debt
|
|
$
|
5,847
|
|
|
$
|
5,661
|
|
|
$
|
6,924
|
|
|
$
|
5,568
|
|
|
$
|
5,957
|
|
Stockholders equity
|
|
$
|
15,570
|
|
|
$
|
17,060
|
|
|
$
|
22,006
|
|
|
$
|
17,442
|
|
|
$
|
14,862
|
|
|
|
|
(1) |
|
During 2009 and 2008, we recorded noncash reductions of carrying
value of oil and gas properties totaling $6.4 billion
($4.1 billion after income taxes) and $9.9 billion
($6.7 billion after income taxes), respectively, related to
our continuing operations as discussed in Note 15 of the
consolidated financial statements. During 2009, 2008 and 2007 we
recorded noncash reductions of carrying value of oil and gas
properties totaling $108 million ($105 million after
taxes), $494 million ($465 million after taxes) and
$68 million ($13 million after taxes) related to our
discontinued operations as discussed in Note 18 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 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
preferred stock that was outstanding until June 2008. |
|
|
|
For 2009, earnings from continuing operations were inadequate to
cover fixed charges by $4.6 billion. For 2008, earnings
from continuing operations were inadequate to cover fixed
charges and combined fixed charges and preferred stock dividends
by $4.2 billion. These earnings relationships were
primarily the result of the noncash reductions 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 our discontinued
international operations. The price data presented excludes the
effects of unrealized and realized gains and losses from our oil
and gas derivative financial instruments. |
|
(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 2009 Results
|
|
|
|
Business and Industry Outlook
|
|
|
|
Results of Operations
|
|
|
|
Capital Resources, Uses and Liquidity
|
|
|
|
Contingencies and Legal Matters
|
33
|
|
|
|
|
Critical Accounting Policies and Estimates
|
|
|
|
Forward-Looking Estimates
|
Overview
of Business
Devon is one of North Americas leading independent oil and
gas exploration and production companies. Our operations are
focused in the United States and Canada. 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.
As an enterprise, we strive to optimize value for our
shareholders by growing reserves, production, earnings and cash
flows, all on a per share basis. We accomplish this by
replenishing our reserves and production and managing other key
operational elements that drive our success. These items are
discussed more fully below.
|
|
|
|
|
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 2010 investment in
capital projects is dedicated to a foundation of low-risk
projects in our North American Onshore properties. The remainder
of our capital has been identified for longer-term projects
primarily in new unconventional natural gas plays in several
U.S. Onshore regions, as well as offshore activities in the
Gulf of Mexico. 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. The timing of closing the planned
sales of our Gulf of Mexico properties will impact exactly how
much of our 2010 capital is used on our Gulf of Mexico assets.
|
|
|
|
|
High margin assets Like many investors, we
seek to invest our capital resources into projects where we can
generate the highest risk-adjusted investment returns. One
factor that can have a significant impact on such returns is our
drilling success rates. Combined with appropriate revenue and
cost-management strategies, high drilling success rates are
important to generating competitive returns on our capital
investment. During 2009, we drilled 1,135 wells and 99% of
those were successful. The success rate is similar to our
drilling achievements in recent years, demonstrating a proven
track record of success. By accomplishing high drilling success
rates, we provide an inventory of reserves growth and a platform
of opportunities on our undrilled acreage that can be profitably
developed.
|
|
|
|
Reserves and production balance As evidenced
by history, commodity prices are inherently volatile. In
addition, oil and gas prices often diverge due to a variety of
circumstances. Consequently, we value a balance of reserves and
production between gas and liquids that can add stability to our
revenue stream when either commodity price is under pressure.
Our production mix in 2009 was
|
34
|
|
|
|
|
approximately 70% gas and 30% oil and NGLs such as propane,
butane and ethane. Our year-end reserves were approximately 60%
gas and 40% liquids. With planned future growth in oil from our
Jackfish and other projects, combined with an inventory of shale
natural gas plays, we expect to maintain this balance in the
future.
|
|
|
|
|
|
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 and 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 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 utilize financial hedging
arrangements and fixed-price physical delivery contracts. As of
February 15, 2010, approximately 53% of our 2010 gas
production is associated with financial price swaps and collars.
Additionally, approximately 65% of our 2010 oil production is
associated with financial price collars.
|
|
|
|
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 2009 Results
2009 was a pivotal year for us as we began repositioning
Devon to focus entirely on our high-return, North American
Onshore natural gas and oil portfolio. We grew North American
Onshore production more than six percent in 2009 and replaced
more than twice our production with the drill bit at very
attractive costs. The performance of these assets is reflected
in our earnings, which steadily increased over the last three
quarters of 2009.
However, our full year 2009 results were significantly impacted
by the downward pressure in oil and natural gas prices that
began in the last half of 2008 and continued throughout 2009.
The Henry Hub natural gas index average for 2009 was 56% lower
than 2008. Although crude prices have improved since the end of
2008, the 2009 West Texas Intermediate oil index average
was 38% lower than 2008.
The lower oil and gas prices significantly impacted our first
quarter 2009 earnings, which in turn impacted our full year
earnings. During 2009, we incurred a net loss of
$2.5 billion, or $5.58 per diluted share. These amounts are
the result of a noncash impairment of our oil and gas properties
that was recognized in the first quarter of 2009 and totaled
$4.2 billion, net of income taxes. Substantially all of
this noncash charge was the result of the drop in natural gas
prices during the first quarter of 2009.
Key measures of our performance for 2009, as well as certain
operational developments, are summarized below:
|
|
|
|
|
Production grew 4% over 2008, to 233 million Boe.
|
35
|
|
|
|
|
The combined realized price for oil, gas and NGLs per Boe
decreased 50% to $26.15.
|
|
|
|
Oil and gas hedges generated net gains of $384 million in
2009, including cash receipts of $505 million.
|
|
|
|
Marketing and midstream operating profit decreased 25% to
$512 million.
|
|
|
|
Per unit lease operating costs decreased 14% to $7.16 per Boe.
|
|
|
|
Operating cash flow decreased to $4.7 billion, representing
a 50% decrease over 2008.
|
|
|
|
Capitalized costs incurred in our oil and gas activities were
$4.1 billion in 2009.
|
From an operational perspective, we completed another successful
year with the drill-bit. We drilled 1,135 gross wells with
an overall 99% rate of success. This success rate enabled us to
increase proved reserves by 496 million Boe, which was more
than double our 2009 production. Our drilling success was driven
by North American Onshore development wells, which represented
95% of the wells drilled.
Besides another successful year of North American Onshore
drilling, we had several other key operational achievements
during 2009. The first phase of our 100%-owned Jackfish thermal
heavy oil project in the Alberta oil sands was operational
throughout 2009. As measured by production per well and
steam-to-oil
ratio, Jackfish is one of Canadas most successful
steam-assisted gravity drainage projects. In late 2009,
Jackfishs gross production reached 33.7 MBbls of oil
per day. The addition of four more producing wells is expected
to push production to the facilitys capacity of
35 MBbls per day in early 2010.
We continued construction throughout 2009 on a second phase of
the Jackfish project. Jackfish 2 is also sized to produce
35 MBbls of oil per day and will commence operations in
2011. Further expansion into a third phase of Jackfish is
planned for 2010. We expect to file a regulatory application for
Jackfish 3 in the third quarter of 2010.
Elsewhere in North America, we are expanding and developing five
natural gas shale plays where we own a total of 1.6 million
net acres. At the Barnett Shale, the most mature of our shale
plays, we pushed our total producing wells to almost 4,200 at
the end of 2009, and we exited the year producing just over one
Bcfe per day. In the Cana-Woodford Shale and Arkoma-Woodford
Shale, we drilled a total of 108 wells, increasing reserves
to 120 MMBoe. In the Haynesville Shale, our drilling has
been focused on de-risking our acreage in the greater Carthage
area of east Texas. Finally, at Horn River, we have assembled a
portfolio of acreage that requires minimal drilling to hold. We
are in the early stages of evaluating the full potential of
these leases and formulating a development plan.
Even with the net loss, we maintained a solid financial position
throughout 2009. We used operating cash flow, borrowings and
cash on hand to fund $5.3 billion of capital expenditures
and pay $284 million of dividends. At the end of 2009, we
had $1.0 billion of cash and $1.8 billion of
availability under our credit lines.
Business
and Industry Outlook
Over the past decade we captured an abundance of resources. We
pioneered horizontal drilling in the Barnett Shale field in
north Texas and extended this technique to other natural gas
shale plays in the United States and Canada. We became
proficient with steam-assisted gravity drainage with our
Jackfish oil sands development in Alberta, Canada. We achieved
key oil discoveries with our drilling in the deepwater Gulf of
Mexico and offshore Brazil. We have more than tripled our proved
oil and gas reserves since 2000 and have also assembled an
extensive inventory of exploration assets, representing
additional unproved resources.
Building off our past successes, in November 2009, we announced
plans to strategically reposition Devon as a high-growth, North
American onshore exploration and production company. As part of
this strategic repositioning, we plan to bring forward the value
of our offshore assets located in the Gulf of Mexico and
countries outside North America by divesting them.
36
This repositioning is driven by our desire to unlock and
accelerate the realization of the value underlying the deep
inventory of opportunities we have. We have assembled a valuable
portfolio of offshore assets, and we have a considerable
inventory of premier North American onshore assets. However, our
North American Onshore assets have consistently provided us our
highest risk-adjusted investment returns. By selling our
offshore assets, we can more aggressively pursue the untapped
value of these North American Onshore opportunities.
We expect to receive after-tax proceeds of between
$4.5 billion and $7.5 billion as we divest our
U.S. Offshore and International properties in 2010. By
using a portion of these proceeds to reduce debt, we will
further strengthen our balance sheet. Besides reducing debt, the
offshore divestiture proceeds are expected to provide
significant funds to redeploy into our prolific North American
Onshore opportunities. With these added funds, we plan to
accelerate the growth and realization of the value of our North
American Onshore assets.
Results
of Operations
As previously stated, we are in the process of divesting our
offshore assets. As a result, all amounts in this document
related to our International operations are presented as
discontinued. Therefore, the production, revenue and expense
amounts presented in this Results of Operations
section exclude amounts related to our International assets
unless otherwise noted. Even though we are also divesting our
U.S. Offshore operations, these properties do not qualify
as discontinued operations under accounting rules. As such,
financial and operating data provided in this document that
pertain to our continuing operations include amounts related to
our U.S. Offshore operations. To facilitate comparisons of
our ongoing operations subsequent to the planned divestitures,
we have presented amounts related to our U.S. Offshore
assets separate from those of our North American Onshore assets
where appropriate.
Unless otherwise stated, all dollar amounts are expressed in
U.S. dollars.
Revenues
Our oil, gas and NGL production volumes from 2007 to 2009 are
shown in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2009 vs.
|
|
|
|
|
|
2008 vs.
|
|
|
|
|
|
|
2009
|
|
|
2008(2)
|
|
|
2008
|
|
|
2007(2)
|
|
|
2007
|
|
|
Oil (MMBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
|
12
|
|
|
|
+3
|
%
|
|
|
11
|
|
|
|
+0
|
%
|
|
|
11
|
|
Canada
|
|
|
25
|
|
|
|
+17
|
%
|
|
|
22
|
|
|
|
+34
|
%
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North American Onshore
|
|
|
37
|
|
|
|
+12
|
%
|
|
|
33
|
|
|
|
+20
|
%
|
|
|
27
|
|
U.S. Offshore
|
|
|
5
|
|
|
|
−15
|
%
|
|
|
6
|
|
|
|
−24
|
%
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
42
|
|
|
|
+8
|
%
|
|
|
39
|
|
|
|
+10
|
%
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Bcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
|
698
|
|
|
|
+5
|
%
|
|
|
669
|
|
|
|
+20
|
%
|
|
|
558
|
|
Canada
|
|
|
223
|
|
|
|
+5
|
%
|
|
|
212
|
|
|
|
−6
|
%
|
|
|
227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North American Onshore
|
|
|
921
|
|
|
|
+5
|
%
|
|
|
881
|
|
|
|
+12
|
%
|
|
|
785
|
|
U.S. Offshore
|
|
|
45
|
|
|
|
−22
|
%
|
|
|
57
|
|
|
|
−25
|
%
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
966
|
|
|
|
+3
|
%
|
|
|
938
|
|
|
|
+9
|
%
|
|
|
862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2009 vs.
|
|
|
|
|
|
2008 vs.
|
|
|
|
|
|
|
2009
|
|
|
2008(2)
|
|
|
2008
|
|
|
2007(2)
|
|
|
2007
|
|
|
NGLs (MMBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
|
25
|
|
|
|
+9
|
%
|
|
|
24
|
|
|
|
+14
|
%
|
|
|
21
|
|
Canada
|
|
|
4
|
|
|
|
−5
|
%
|
|
|
4
|
|
|
|
−6
|
%
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North American Onshore
|
|
|
29
|
|
|
|
+7
|
%
|
|
|
28
|
|
|
|
+11
|
%
|
|
|
25
|
|
U.S. Offshore
|
|
|
1
|
|
|
|
+27
|
%
|
|
|
|
|
|
|
−26
|
%
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
30
|
|
|
|
+7
|
%
|
|
|
28
|
|
|
|
+10
|
%
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMBoe)(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
|
154
|
|
|
|
+5
|
%
|
|
|
146
|
|
|
|
+17
|
%
|
|
|
124
|
|
Canada
|
|
|
66
|
|
|
|
+9
|
%
|
|
|
61
|
|
|
|
+5
|
%
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North American Onshore
|
|
|
220
|
|
|
|
+6
|
%
|
|
|
207
|
|
|
|
+13
|
%
|
|
|
182
|
|
U.S. Offshore
|
|
|
13
|
|
|
|
−18
|
%
|
|
|
16
|
|
|
|
−25
|
%
|
|
|
22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
233
|
|
|
|
+4
|
%
|
|
|
223
|
|
|
|
+9
|
%
|
|
|
204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
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. |
|
(2) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in the table. |
The following table presents the prices we realized on our
production volumes from 2007 to 2009. These prices exclude any
effects due to our oil and gas derivative financial instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2009 vs.
|
|
|
|
|
|
2008 vs.
|
|
|
|
|
|
|
2009
|
|
|
2008(2)
|
|
|
2008
|
|
|
2007(2)
|
|
|
2007
|
|
|
Oil (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
$
|
56.17
|
|
|
|
−41
|
%
|
|
$
|
95.63
|
|
|
|
+42
|
%
|
|
$
|
67.34
|
|
Canada
|
|
$
|
47.35
|
|
|
|
−33
|
%
|
|
$
|
71.04
|
|
|
|
+43
|
%
|
|
$
|
49.80
|
|
North American Onshore
|
|
$
|
50.11
|
|
|
|
−37
|
%
|
|
$
|
79.45
|
|
|
|
+39
|
%
|
|
$
|
56.99
|
|
U.S. Offshore
|
|
$
|
60.75
|
|
|
|
−42
|
%
|
|
$
|
104.90
|
|
|
|
+46
|
%
|
|
$
|
71.95
|
|
Total
|
|
$
|
51.39
|
|
|
|
−38
|
%
|
|
$
|
83.35
|
|
|
|
+38
|
%
|
|
$
|
60.30
|
|
Gas (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
$
|
3.14
|
|
|
|
−58
|
%
|
|
$
|
7.43
|
|
|
|
+30
|
%
|
|
$
|
5.69
|
|
Canada
|
|
$
|
3.66
|
|
|
|
−55
|
%
|
|
$
|
8.17
|
|
|
|
+31
|
%
|
|
$
|
6.24
|
|
North American Onshore
|
|
$
|
3.27
|
|
|
|
−57
|
%
|
|
$
|
7.61
|
|
|
|
+30
|
%
|
|
$
|
5.85
|
|
U.S. Offshore
|
|
$
|
4.20
|
|
|
|
−56
|
%
|
|
$
|
9.53
|
|
|
|
+33
|
%
|
|
$
|
7.17
|
|
Total
|
|
$
|
3.31
|
|
|
|
−57
|
%
|
|
$
|
7.73
|
|
|
|
+29
|
%
|
|
$
|
5.97
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2009 vs.
|
|
|
|
|
|
2008 vs.
|
|
|
|
|
|
|
2009
|
|
|
2008(2)
|
|
|
2008
|
|
|
2007(2)
|
|
|
2007
|
|
|
NGLs (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
$
|
23.40
|
|
|
|
−43
|
%
|
|
$
|
40.97
|
|
|
|
+14
|
%
|
|
$
|
36.08
|
|
Canada
|
|
$
|
33.09
|
|
|
|
−46
|
%
|
|
$
|
61.45
|
|
|
|
+33
|
%
|
|
$
|
46.07
|
|
North American Onshore
|
|
$
|
24.65
|
|
|
|
−44
|
%
|
|
$
|
43.94
|
|
|
|
+16
|
%
|
|
$
|
37.80
|
|
U.S. Offshore
|
|
$
|
27.42
|
|
|
|
−46
|
%
|
|
$
|
51.11
|
|
|
|
+39
|
%
|
|
$
|
36.78
|
|
Total
|
|
$
|
24.71
|
|
|
|
−44
|
%
|
|
$
|
44.08
|
|
|
|
+17
|
%
|
|
$
|
37.76
|
|
Combined (per Boe)(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
$
|
22.41
|
|
|
|
−53
|
%
|
|
$
|
47.91
|
|
|
|
+28
|
%
|
|
$
|
37.45
|
|
Canada
|
|
$
|
32.29
|
|
|
|
−44
|
%
|
|
$
|
57.65
|
|
|
|
+39
|
%
|
|
$
|
41.51
|
|
North American Onshore
|
|
$
|
25.38
|
|
|
|
−50
|
%
|
|
$
|
50.78
|
|
|
|
+31
|
%
|
|
$
|
38.74
|
|
U.S. Offshore
|
|
$
|
38.83
|
|
|
|
−48
|
%
|
|
$
|
74.55
|
|
|
|
+40
|
%
|
|
$
|
53.30
|
|
Total
|
|
$
|
26.15
|
|
|
|
−50
|
%
|
|
$
|
52.49
|
|
|
|
+30
|
%
|
|
$
|
40.26
|
|
|
|
|
(1) |
|
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. |
|
(2) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in the table. |
The volume and price changes in the tables above caused the
following changes to our oil, gas and NGL sales between 2007 and
2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGL
|
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
2007 sales
|
|
$
|
2,117
|
|
|
$
|
5,138
|
|
|
$
|
970
|
|
|
$
|
8,225
|
|
Changes due to volumes
|
|
|
222
|
|
|
|
459
|
|
|
|
95
|
|
|
|
776
|
|
Changes due to prices
|
|
|
894
|
|
|
|
1,647
|
|
|
|
178
|
|
|
|
2,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 sales
|
|
|
3,233
|
|
|
|
7,244
|
|
|
|
1,243
|
|
|
|
11,720
|
|
Changes due to volumes
|
|
|
258
|
|
|
|
222
|
|
|
|
89
|
|
|
|
569
|
|
Changes due to prices
|
|
|
(1,338
|
)
|
|
|
(4,269
|
)
|
|
|
(585
|
)
|
|
|
(6,192
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 sales
|
|
$
|
2,153
|
|
|
$
|
3,197
|
|
|
$
|
747
|
|
|
$
|
6,097
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
Sales
2009 vs. 2008 Oil sales decreased $1.3 billion as a
result of a 38% decrease in our realized price without hedges.
The average NYMEX West Texas Intermediate index price decreased
38% during the same time period, accounting for the majority of
the decrease in our realized price.
Oil sales increased $258 million due to a three million
barrel, or 8%, increase in production. The increased production
resulted primarily from the continued development of our
Jackfish thermal heavy oil project in Canada.
2008 vs. 2007 Oil sales increased $894 million as a
result of a 38% 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 in our realized price.
Oil sales increased $222 million due to a four million
barrel, or 10%, increase in production. Production from our
Canadian operations increased approximately six million barrels
in 2008 as a result of first oil sales
39
at Jackfish and heavy oil development activity at Lloydminster.
This increase was partially offset by the deferral of
0.5 million barrels of oil production from our
U.S. Offshore properties due to hurricanes.
Gas
Sales
2009 vs. 2008 Gas sales decreased $4.3 billion as a
result of a 57% decrease in our realized price without hedges.
This decrease was largely due to decreases in the North American
regional index prices upon which our gas sales are based.
A 28 Bcf, or 3%, increase in production during 2009 caused
gas sales to increase by $222 million. Our North American
Onshore properties contributed 40 Bcf of higher volumes.
This increase included 25 Bcf of higher production in
Canada due to a decline in Canadian government royalties,
resulting largely from lower gas prices. The remainder of the
North American Onshore growth resulted from new drilling and
development that exceeded natural production declines, primarily
in the Barnett Shale field in north Texas. These increases were
partially offset by 12 Bcf of lower production from our
U.S. Offshore properties, largely resulting from natural
production declines.
2008 vs. 2007 Gas sales increased $1.6 billion as a
result of a 29% increase in our realized price without hedges.
This increase was largely due to increases in the North American
regional index prices upon which our gas sales are based.
A 76 Bcf, or 9%, increase in production during 2008 caused
gas sales to increase by $459 million. Our North American
Onshore properties contributed 96 Bcf to our growth as a
result of new drilling and development that exceeded natural
production declines. This increase was led by our drilling and
development program in the Barnett Shale, which contributed
83 Bcf to the gas production increase. This increase and
the effect of new drilling and development in our other North
American Onshore properties were partially offset by natural
production declines and the deferral of seven Bcf of production
in our U.S. Offshore properties in 2008 due to hurricanes.
NGL
Sales
2009 vs. 2008 NGL sales decreased $585 million as a
result of a 44% decrease in our realized price without hedges.
This decrease was largely due to decreases in the regional index
prices upon which our U.S. Onshore NGL sales are based. NGL
sales increased $89 million in 2009 due to a two million
barrel, or 7%, increase in production. The increase in
production is primarily due to drilling and development in the
Barnett Shale.
2008 vs. 2007 NGL sales increased $178 million as a
result of a 17% increase in our realized price without hedges.
This increase was largely due to increases in the regional index
prices upon which our U.S. Onshore NGL sales are based. NGL
sales increased $95 million in 2008 due to a two million
barrel, or 10%, increase in production. The increase in
production is primarily due to Barnett Shale drilling and
development.
40
Net Gain
(Loss) on Oil and Gas Derivative Financial Instruments
The following tables provide financial information associated
with our oil and gas derivative financial instruments from 2007
to 2009. 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 2007 to 2009. The prices do not include the effects of
unrealized gains and losses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Cash settlement receipts (payments):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price collars
|
|
$
|
450
|
|
|
$
|
(221
|
)
|
|
$
|
2
|
|
Gas price swaps
|
|
|
55
|
|
|
|
(203
|
)
|
|
|
38
|
|
Oil price collars
|
|
|
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements
|
|
|
505
|
|
|
|
(397
|
)
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (losses) gains on fair value changes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price collars
|
|
|
(255
|
)
|
|
|
255
|
|
|
|
(4
|
)
|
Gas price swaps
|
|
|
169
|
|
|
|
(12
|
)
|
|
|
(22
|
)
|
Gas basis swaps
|
|
|
3
|
|
|
|
|
|
|
|
|
|
Oil price collars
|
|
|
(38
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized (losses) gains on fair value changes
|
|
|
(121
|
)
|
|
|
243
|
|
|
|
(26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss)
|
|
$
|
384
|
|
|
$
|
(154
|
)
|
|
$
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
Total
|
|
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Boe)
|
|
|
Realized price without hedges
|
|
$
|
51.39
|
|
|
$
|
3.31
|
|
|
$
|
24.71
|
|
|
$
|
26.15
|
|
Cash settlements of hedges
|
|
|
|
|
|
|
0.52
|
|
|
|
|
|
|
|
2.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements
|
|
$
|
51.39
|
|
|
$
|
3.83
|
|
|
$
|
24.71
|
|
|
$
|
28.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
Total
|
|
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Boe)
|
|
|
Realized price without hedges
|
|
$
|
83.35
|
|
|
$
|
7.73
|
|
|
$
|
44.08
|
|
|
$
|
52.49
|
|
Cash settlements of hedges
|
|
|
0.70
|
|
|
|
(0.46
|
)
|
|
|
|
|
|
|
(1.78
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements
|
|
$
|
84.05
|
|
|
$
|
7.27
|
|
|
$
|
44.08
|
|
|
$
|
50.71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
Total
|
|
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Boe)
|
|
|
Realized price without hedges
|
|
$
|
60.30
|
|
|
$
|
5.97
|
|
|
$
|
37.76
|
|
|
$
|
40.26
|
|
Cash settlements of hedges
|
|
|
|
|
|
|
0.04
|
|
|
|
|
|
|
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements
|
|
$
|
60.30
|
|
|
$
|
6.01
|
|
|
$
|
37.76
|
|
|
$
|
40.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our oil and gas derivative financial instruments include price
swaps, basis 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. For the
basis swaps, we receive a fixed differential between two
regional gas index prices and pay a variable differential on the
same two index prices to the contract counterparty. The price
collars set a floor and ceiling price. If the applicable monthly
price indices are outside of the ranges set by the
41
floor and ceiling prices in the various collars, we cash-settle
the difference with the counterparty to the collars. Cash
settlements as presented in the tables above represent realized
gains or losses related to our price swaps and collars.
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. We periodically 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 our gas
price swaps and collars at December 31, 2009, a 10%
increase in these forward curves would have increased our 2009
unrealized losses for our gas derivative financial instruments
by approximately $264 million. A 10% increase in the
forward curves associated with our oil derivative financial
instruments would have increased our 2009 unrealized losses by
approximately $108 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 twelve 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
mark-to-market
exposure threshold, above which collateral must be posted,
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, 2009, the credit ratings of all our
counterparties were investment grade.
During 2009, the fair value of our oil and gas derivative
financial instruments dropped by $121 million. This
reduction largely resulted from the reversal of previously
recorded unrealized gains on our gas price collar contracts,
which was expected as the contracts settled throughout 2009 and
expired on December 31, 2009. This reduction, as well as
the reduction related to our oil price collars, were partially
offset by unrealized gains on gas swap contracts that we entered
into during 2009 and will be settled throughout 2010.
During 2008, the fair value of our gas derivative financial
instruments increased by $243 million, which was largely
due to a decrease in the Inside FERC Henry Hub forward curve.
Marketing
and Midstream Revenues and Operating Costs and
Expenses
The changes in marketing and midstream revenues, operating costs
and expenses and the resulting operating profit between 2007 and
2009 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2009 vs
|
|
|
|
|
|
2008 vs
|
|
|
|
|
|
|
2009
|
|
|
2008(1)
|
|
|
2008
|
|
|
2007(1)
|
|
|
2007
|
|
|
|
($ in millions)
|
|
|
Marketing and midstream:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
1,534
|
|
|
|
−33
|
%
|
|
$
|
2,292
|
|
|
|
+32
|
%
|
|
$
|
1,736
|
|
Operating costs and expenses
|
|
|
1,022
|
|
|
|
−37
|
%
|
|
|
1,611
|
|
|
|
+32
|
%
|
|
|
1,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit
|
|
$
|
512
|
|
|
|
−25
|
%
|
|
$
|
681
|
|
|
|
+31
|
%
|
|
$
|
519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in this
table. |
2009 vs. 2008 Marketing and midstream revenues decreased
$758 million and operating costs and expenses decreased
$589 million, causing operating profit to decrease
$169 million. Both revenues and
42
expenses decreased primarily due to lower natural gas and NGL
prices, partially offset by higher NGL production and gas
pipeline throughput.
2008 vs. 2007 Marketing and midstream revenues increased
$556 million and operating costs and expenses increased
$394 million, causing operating profit to increase
$162 million. Both revenues and expenses increased
primarily due to higher natural gas and NGL prices and increased
gas pipeline throughput.
Lease
Operating Expenses (LOE)
The changes in LOE between 2007 and 2009 are shown in the table
below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2009 vs.
|
|
|
|
|
|
2008 vs.
|
|
|
|
|
|
|
2009
|
|
|
2008(1)
|
|
|
2008
|
|
|
2007(1)
|
|
|
2007
|
|
|
Lease operating expenses ($ in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
$
|
838
|
|
|
|
−6
|
%
|
|
$
|
893
|
|
|
|
+25
|
%
|
|
$
|
712
|
|
Canada
|
|
|
673
|
|
|
|
−13
|
%
|
|
|
776
|
|
|
|
+24
|
%
|
|
|
627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North American Onshore
|
|
|
1,511
|
|
|
|
−10
|
%
|
|
|
1,669
|
|
|
|
+25
|
%
|
|
|
1,339
|
|
U.S. Offshore
|
|
|
159
|
|
|
|
−13
|
%
|
|
|
182
|
|
|
|
−6
|
%
|
|
|
193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,670
|
|
|
|
−10
|
%
|
|
$
|
1,851
|
|
|
|
+21
|
%
|
|
$
|
1,532
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore
|
|
$
|
5.46
|
|
|
|
−11
|
%
|
|
$
|
6.11
|
|
|
|
+7
|
%
|
|
$
|
5.70
|
|
Canada
|
|
$
|
10.15
|
|
|
|
−20
|
%
|
|
$
|
12.74
|
|
|
|
+18
|
%
|
|
$
|
10.80
|
|
North American Onshore
|
|
$
|
6.87
|
|
|
|
−15
|
%
|
|
$
|
8.06
|
|
|
|
+10
|
%
|
|
$
|
7.32
|
|
U.S. Offshore
|
|
$
|
11.98
|
|
|
|
+6
|
%
|
|
$
|
11.29
|
|
|
|
+25
|
%
|
|
$
|
9.04
|
|
Total
|
|
$
|
7.16
|
|
|
|
−14
|
%
|
|
$
|
8.29
|
|
|
|
+11
|
%
|
|
$
|
7.50
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in this
table. |
2009 vs. 2008 LOE decreased $181 million in 2009.
LOE dropped $182 million due to declining costs for fuel,
materials, equipment and personnel, as well as declines in
maintenance and well workover projects. Such declines largely
resulted from decreasing demand for field services due to lower
oil and gas prices. Changes in the exchange rate between the
U.S. and Canadian dollar reduced LOE $49 million.
Additionally, LOE decreased $31 million as a result of
hurricane damages in 2008 to certain of our U.S. Offshore
facilities and transportation systems. These factors were also
the main contributors to the decrease in LOE per Boe on our
North American Onshore properties. Production growth at our
large-scale Jackfish project also contributed to a decrease in
LOE per Boe. As Jackfish production approached the
facilitys capacity during 2009, its
per-unit
costs declined, contributing to lower overall LOE per Boe. The
remainder of our 4% production growth added $81 million to
LOE during 2009.
2008 vs. 2007 LOE increased $319 million in 2008.
The largest individual contributor to this increase, as well as
the increase in LOE per Boe, was higher
per-unit
costs associated with the new thermal heavy oil production at
Jackfish in 2008. When large-scale projects such as Jackfish are
in the early phases of production,
per-unit
operating costs are normally higher than the
per-unit
costs for our overall portfolio of producing properties. LOE
also increased $144 million due to our 9% growth in
production. Additionally, LOE increased $31 million due to
hurricane damages in 2008 to certain of our U.S. Offshore
facilities and transportation systems. These hurricane damages
also contributed to the increase in LOE per Boe.
43
Taxes
Other Than Income Taxes
Taxes other than income taxes primarily consist of production
taxes and ad valorem taxes assessed by various government
agencies on our U.S. Onshore properties. Production taxes
are based on a percentage of production revenues that varies by
property and government jurisdiction. Ad valorem taxes generally
are based on property values as determined by the government
agency assessing the tax. The following table details the
changes in our taxes other than income taxes between 2007 and
2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2009 vs
|
|
|
|
|
|
2008 vs
|
|
|
|
|
|
|
2009
|
|
|
2008(1)
|
|
|
2008
|
|
|
2007(1)
|
|
|
2007
|
|
|
|
($ in millions)
|
|
|
Production
|
|
$
|
132
|
|
|
|
−57
|
%
|
|
$
|
306
|
|
|
|
+41
|
%
|
|
$
|
216
|
|
Ad valorem
|
|
|
175
|
|
|
|
+8
|
%
|
|
|
162
|
|
|
|
+19
|
%
|
|
|
135
|
|
Other
|
|
|
7
|
|
|
|
−4
|
%
|
|
|
8
|
|
|
|
+20
|
%
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
314
|
|
|
|
−34
|
%
|
|
$
|
476
|
|
|
|
+33
|
%
|
|
$
|
358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in this
table. |
2009 vs. 2008 Production taxes decreased
$174 million in 2009. This decrease was largely due to
lower U.S. Onshore revenues, as well as an increase in tax
credits associated with certain properties in the state of
Texas. Ad valorem taxes increased $13 million primarily due
to higher assessed oil and gas property and equipment values.
2008 vs. 2007 Production taxes increased $90 million
in 2008 primarily due to an increase in our U.S. Onshore
revenues. Ad valorem taxes increased $27 million primarily
due to higher assessed oil and gas property and equipment values.
Depreciation,
Depletion and Amortization of Oil and Gas Properties
(DD&A)
DD&A of oil and gas properties is calculated by multiplying
the percentage of total proved reserve volumes produced during
the year, by the depletable base. The depletable
base represents our capitalized investment, net of accumulated
DD&A and reductions of carrying value, plus future
development costs related to proved undeveloped reserves.
Generally, when reserve volumes are revised up or down, then the
DD&A rate per unit of production will change inversely.
However, when the depletable base changes, then the DD&A
rate moves in the same direction. The per unit DD&A rate is
not affected by production volumes. Absolute or total DD&A,
as opposed to the rate per unit of production, generally moves
in the same direction as production volumes. Oil and gas
property DD&A is calculated separately on a
country-by-country
basis.
The changes in our production volumes, DD&A rate per unit
and DD&A of oil and gas properties between 2007 and 2009
are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2009 vs
|
|
|
|
|
|
2008 vs
|
|
|
|
|
|
|
2009
|
|
|
2008(1)
|
|
|
2008
|
|
|
2007(1)
|
|
|
2007
|
|
|
Total production volumes (MMBoe)
|
|
|
233
|
|
|
|
+4
|
%
|
|
|
223
|
|
|
|
+9
|
%
|
|
|
204
|
|
DD&A rate ($ per Boe)
|
|
$
|
7.86
|
|
|
|
−40
|
%
|
|
$
|
13.20
|
|
|
|
+12
|
%
|
|
$
|
11.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A expense ($ in millions)
|
|
$
|
1,832
|
|
|
|
−38
|
%
|
|
$
|
2,948
|
|
|
|
+22
|
%
|
|
$
|
2,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in this
table. |
44
The following table details the changes in DD&A of oil and
gas properties between 2007 and 2009 due to the changes in
production volumes and DD&A rate presented in the table
above.
|
|
|
|
|
|
|
(In millions)
|
|
|
2007 DD&A
|
|
$
|
2,412
|
|
Change due to volumes
|
|
|
224
|
|
Change due to rate
|
|
|
312
|
|
|
|
|
|
|
2008 DD&A
|
|
|
2,948
|
|
Change due to volumes
|
|
|
130
|
|
Change due to rate
|
|
|
(1,246
|
)
|
|
|
|
|
|
2009 DD&A
|
|
$
|
1,832
|
|
|
|
|
|
|
2009 vs. 2008 Oil and gas property related DD&A
decreased $1.2 billion due to a 40% decrease in the
DD&A rate. The largest contributors to the rate decrease
were reductions of the carrying values of certain of our oil and
gas properties recognized in the first quarter of 2009 and the
fourth quarter of 2008. These reductions totaled
$16.3 billion and resulted from full cost ceiling
limitations in the United States and Canada. In addition, the
effects of changes in the exchange rate between the
U.S. and Canadian dollar also contributed to the rate
decrease. These factors were partially offset by the effects of
costs incurred and the transfer of previously unproved costs to
the depletable base as a result of 2009 drilling activities.
Partially offsetting the impact from the lower 2009 DD&A
rate was our 4% production increase, which caused oil and gas
property related DD&A expense to increase $130 million.
Our 2009 DD&A rate reflects our adoption of the SECs
Modernization of Oil and Gas Reporting. The impact of
adopting the SECs new rules at the end of 2009 had
virtually no impact on our 2009 DD&A rate.
2008 vs. 2007 Oil and gas property related DD&A
increased $312 million due to a 12% 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 that
contributed to the rate increase were 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, the 9% production increase
caused oil and gas property related DD&A expense to
increase $224 million.
General
and Administrative Expenses (G&A)
Our net G&A consists of three primary components. The
largest of these components is the gross amount of expenses
incurred for personnel costs, office expenses, professional fees
and other G&A items. The gross amount of these expenses is
partially offset by two components. One is the amount of
G&A capitalized pursuant to the full cost method of
accounting related to exploration and development activities.
The other is the amount of G&A reimbursed by working
interest owners of properties for which we serve as the
operator. These reimbursements are received during both the
drilling and operational stages of a propertys life. The
gross amount of G&A incurred, less the amounts capitalized
and reimbursed, is recorded as net G&A in the consolidated
statements of operations. Net G&A includes expenses related
to oil, gas and NGL exploration
45
and production activities, as well as marketing and midstream
activities. See the following table for a summary of G&A
expenses by component.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2009 vs
|
|
|
|
|
|
2008 vs
|
|
|
|
|
|
|
2009
|
|
|
2008(1)
|
|
|
2008
|
|
|
2007(1)
|
|
|
2007
|
|
|
|
($ in millions)
|
|
|
Gross G&A
|
|
$
|
1,107
|
|
|
|
+0
|
%
|
|
$
|
1,103
|
|
|
|
+24
|
%
|
|
$
|
903
|
|
Capitalized G&A
|
|
|
(332
|
)
|
|
|
−2
|
%
|
|
|
(337
|
)
|
|
|
+26
|
%
|
|
|
(277
|
)
|
Reimbursed G&A
|
|
|
(127
|
)
|
|
|
+5
|
%
|
|
|
(121
|
)
|
|
|
+7
|
%
|
|
|
(113
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A
|
|
$
|
648
|
|
|
|
+0
|
%
|
|
$
|
645
|
|
|
|
+26
|
%
|
|
$
|
513
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on
actual figures and not the rounded figures included in this
table. |
2009 vs. 2008 Gross G&A increased $4 million.
This increase was due to approximately $60 million of
higher costs for employee compensation and benefits, mostly
offset by the effects of our 2009 reduced spending initiatives
for certain discretionary cost categories.
Employee cost increases in 2009 included an additional
$57 million of severance costs. This increase was primarily
due to Gulf of Mexico employees that were impacted by the
integration of our Gulf of Mexico and International operations
into one offshore unit in the second quarter of 2009 and other
employee departures during 2009. Additionally, postretirement
benefits costs increased approximately $50 million. The
increases in employee costs were partially offset by a
$27 million decrease due to accelerated share-based
compensation expense recognized in 2008 as discussed below.
2008 vs. 2007 Gross G&A increased $200 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
$164 million. Of this increase, $65 million related to
higher stock compensation.
Stock compensation increased $43 million in 2008 due to a
modification of the share-based compensation arrangements for
certain 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 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.
The higher employee compensation and benefits costs, exclusive
of the accelerated stock compensation expense, were also the
primary factors that caused the $60 million increase in
capitalized G&A in 2008.
Restructuring
Costs
In the fourth quarter of 2009, we recognized $153 million
of estimated employee severance costs associated with the
planned divestitures of our offshore assets that was announced
in November 2009. This amount was based on our estimates of the
number of employees that will ultimately be impacted by the
divestitures, and includes $63 million related to
accelerated vesting of share-based grants. Of the
$153 million
46
total, $105 million relates to our U.S. Offshore
operations and the remainder relates to our International
discontinued operations.
As of the date of this report, only one of the properties we
intend to sell had actually been sold. Furthermore, the vast
majority of employees will not be impacted by the divestitures
until the properties are sold. Therefore, our estimate of
employee severance costs recognized in the fourth quarter of
2009 was based upon certain key estimates that could change as
properties are sold. These estimates include the number of
impacted employees, the number of employees offered comparable
positions with the buyers and the date of separation for
impacted employees. If our estimate of the number of impacted
employees were to increase 10%, our estimate of employee
severance costs would increase approximately $10 million.
If our estimate of the number of employees offered comparable
positions with the buyers were to decrease by 10%, our estimate
of employee severance costs would increase approximately
$15 million. Additionally, if the date of separation were
to occur one month after our current estimates, our estimate of
employee severance costs would increase approximately
$2 million.
Interest
Expense
The following table includes the components of interest expense
between 2007 and 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Interest based on debt outstanding
|
|
$
|
437
|
|
|
$
|
426
|
|
|
$
|
508
|
|
Capitalized interest
|
|
|
(94
|
)
|
|
|
(111
|
)
|
|
|
(102
|
)
|
Other
|
|
|
6
|
|
|
|
14
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense
|
|
$
|
349
|
|
|
$
|
329
|
|
|
$
|
430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 vs. 2008 Interest based on debt outstanding
increased $11 million from 2008 to 2009. This increase was
primarily due to interest paid on the $500 million of
5.625% senior unsecured notes and $700 million of
6.30% senior unsecured notes that we issued in January
2009. This was partially offset by lower interest resulting from
the retirement of our exchangeable debentures during the third
quarter of 2008 and lower interest rates on our floating-rate
commercial paper borrowings.
Capitalized interest decreased from 2008 to 2009 primarily due
to the sales of our West African exploration and development
properties in 2008 and the completion of the Access pipeline
transportation system in Canada in the second quarter of 2008.
2008 vs. 2007 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.
Capitalized interest increased from 2007 to 2008 primarily due
to higher cumulative costs related to large-scale development
projects in the Gulf of Mexico, partially offset by lower
capitalized interest resulting from the completion of the Access
pipeline in the second quarter of 2008.
47
Change
in Fair Value of Other Financial Instruments
The details of the changes in fair value of other financial
instruments between 2007 and 2009 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
(Gains) losses from:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps fair value changes
|
|
$
|
(66
|
)
|
|
$
|
(104
|
)
|
|
$
|
(1
|
)
|
Interest rate swaps settlements
|
|
|
(40
|
)
|
|
|
(1
|
)
|
|
|
|
|
Chevron common stock
|
|
|
|
|
|
|
363
|
|
|
|
(281
|
)
|
Option embedded in exchangeable debentures
|
|
|
|
|
|
|
(109
|
)
|
|
|
248
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(106
|
)
|
|
$
|
149
|
|
|
$
|
(34
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Rate Swaps
We 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. We periodically validate our
valuation techniques by comparing our internally generated fair
value estimates with those obtained from contract counterparties
or brokers. In 2009 and 2008, we recorded unrealized gains of
$66 million and $104 million, respectively, as a
result of changes in interest rates. Also, during 2009 and 2008,
we received cash settlements totaling $40 million and
$1 million, respectively, from counterparties to settle our
interest rate swaps. There were no cash settlements in 2007.
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, 2009, a
10% increase in these forward curves would have increased our
2009 unrealized gain for our interest rate swaps by
approximately $46 million.
Similar to 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 several counterparties. Our
interest rate derivative contracts are held with seven 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
mark-to-market
exposure threshold, above which collateral must be posted,
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. The credit
ratings of all our counterparties were investment grade as of
December 31, 2009.
Chevron
Common Stock and Related Embedded Option
Until October 31, 2008, we owned 14.2 million shares
of Chevron common stock and recognized unrealized changes in the
fair value of this investment. 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.
48
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.
Reduction
of Carrying Value of Oil and Gas Properties
During 2009 and 2008, we reduced the carrying values of certain
of our oil and gas properties due to full cost ceiling
limitations. A summary of these reductions and additional
discussion is provided below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
Net of
|
|
|
|
|
|
Net of
|
|
|
|
Gross
|
|
|
Taxes
|
|
|
Gross
|
|
|
Taxes
|
|
|
|
(In millions)
|
|
|
United States
|
|
$
|
6,408
|
|
|
$
|
4,085
|
|
|
$
|
6,538
|
|
|
$
|
4,168
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
3,353
|
|
|
|
2,488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,408
|
|
|
$
|
4,085
|
|
|
$
|
9,891
|
|
|
$
|
6,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The 2009 reduction was recognized in the first quarter and the
2008 reductions were recognized in the fourth quarter. The
reductions resulted from significant decreases in each
countrys full cost ceiling compared to the immediately
preceding quarter. The lower United States ceiling value in the
first quarter of 2009 largely resulted from the effects of
declining natural gas prices subsequent to December 31,
2008. The lower ceiling values in the fourth quarter of 2008
largely resulted from the effects of sharp declines in oil, gas
and NGL prices compared to September 30, 2008.
To demonstrate these declines, the March 31, 2009,
December 31, 2008 and September 30, 2008 weighted
average wellhead prices are presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2009
|
|
|
December 31, 2008
|
|
|
September 30, 2008
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
Country
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
(Per Bbl)
|
|
|
(Per Mcf)
|
|
|
(Per Bbl)
|
|
|
United States
|
|
$
|
47.30
|
|
|
$
|
2.67
|
|
|
$
|
17.04
|
|
|
$
|
42.21
|
|
|
$
|
4.68
|
|
|
$
|
16.16
|
|
|
$
|
97.62
|
|
|
$
|
5.28
|
|
|
$
|
38.00
|
|
Canada
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
$
|
23.23
|
|
|
$
|
5.31
|
|
|
$
|
20.89
|
|
|
$
|
59.72
|
|
|
$
|
6.00
|
|
|
$
|
62.78
|
|
N/A Not applicable.
The March 31, 2009 oil and gas wellhead prices in the table
above compare to the NYMEX cash price of $49.66 per Bbl for
crude oil and the Henry Hub spot price of $3.63 per MMBtu for
gas. 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.
49
Other
Income
The following table includes the components of other income
between 2007 and 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Interest and dividend income
|
|
$
|
8
|
|
|
$
|
54
|
|
|
$
|
48
|
|
Reduction of deep water royalties
|
|
|
84
|
|
|
|
|
|
|
|
|
|
Hurricane insurance proceeds
|
|
|
|
|
|
|
162
|
|
|
|
|
|
Other
|
|
|
(24
|
)
|
|
|
1
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
68
|
|
|
$
|
217
|
|
|
$
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and dividend income decreased from 2008 to 2009 due to
a decrease in dividends received on our previously owned
investment in Chevron common stock and a decrease in interest
received on cash equivalents due to lower rates and balances.
Interest and dividend income increased from 2007 to 2008
primarily due to higher cash balances partially offset by lower
interest rates and a decrease in dividends received on our
investment in Chevron common stock.
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.
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 was later appealed to the United States Supreme Court,
which, in October 2009, declined to review the appellate
courts ruling. The Supreme Courts decision ended the
MMSs judicial course to enforce the price thresholds.
Prior to September 30, 2009, we had $84 million
accrued for potential royalties on various deep water leases.
Based upon the Supreme Courts decision, we reduced to zero
the $84 million loss contingency accrual in the third
quarter of 2009.
In 2008, we recognized $162 million of excess insurance
recoveries for damages suffered in 2005 related to hurricanes
that struck the Gulf of Mexico. The excess recoveries resulted
from business interruption claims on policies that were in
effect when the 2005 hurricanes occurred.
50
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 2007 to 2009, and
differ from the U.S. statutory rate, are discussed below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Total income tax (benefit) expense (In millions)
|
|
$
|
(1,773
|
)
|
|
$
|
(1,121
|
)
|
|
$
|
842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate
|
|
|
(35
|
)%
|
|
|
(35
|
)%
|
|
|
35
|
%
|
State income taxes
|
|
|
(2
|
)%
|
|
|
(1
|
)%
|
|
|
1
|
%
|
Taxation on Canadian operations
|
|
|
(1
|
)%
|
|
|
5
|
%
|
|
|
|
|
Repatriations and tax policy election changes
|
|
|
|
|
|
|
7
|
%
|
|
|
|
|
Canadian statutory rate reduction
|
|
|
|
|
|
|
|
|
|
|
(8
|
)%
|
Other
|
|
|
(1
|
)%
|
|
|
(3
|
)%
|
|
|
(3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax (benefit) expense rate
|
|
|
(39
|
)%
|
|
|
(27
|
)%
|
|
|
25
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 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 $312 million during 2008. Of the
$312 million, $295 million was recognized as current
income tax expense, and $17 million was recognized as
deferred tax expense. Excluding the $312 million of
additional tax expense, our effective income tax benefit rate
would have been 34% for 2008.
In 2007, deferred income taxes were reduced $261 million
due to a Canadian statutory rate reduction that was enacted in
that year.
Earnings
From Discontinued Operations
For all years presented in the following tables, our
discontinued operations include amounts related to our assets in
Azerbaijan, Brazil, China and other minor International
properties that we are in the process of divesting.
Additionally, during 2007 and 2008, our discontinued operations
included amounts related to our assets in Egypt and West Africa,
including Equatorial Guinea, Cote dIvoire, Gabon and other
countries in the
51
region until they were sold. Following are the components of
earnings from discontinued operations between 2007 and 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Total production (MMBoe)
|
|
|
16
|
|
|
|
18
|
|
|
|
32
|
|
Combined price without hedges (per Boe)
|
|
$
|
59.25
|
|
|
$
|
92.72
|
|
|
$
|
68.11
|
|
|
|
|
|
|
(In millions)
|
Operating revenues
|
|
$
|
945
|
|
|
$
|
1,702
|
|
|
$
|
2,168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
484
|
|
|
|
769
|
|
|
|
597
|
|
Restructuring costs
|
|
|
48
|
|
|
|
|
|
|
|
|
|
Reduction of carrying value of oil and gas properties
|
|
|
108
|
|
|
|
494
|
|
|
|
68
|
|
Gain on sale of oil and gas properties
|
|
|
(17
|
)
|
|
|
(819
|
)
|
|
|
(90
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net
|
|
|
623
|
|
|
|
444
|
|
|
|
575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings before income taxes
|
|
|
322
|
|
|
|
1,258
|
|
|
|
1,593
|
|
Income tax expense
|
|
|
48
|
|
|
|
367
|
|
|
|
472
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations
|
|
$
|
274
|
|
|
$
|
891
|
|
|
$
|
1,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our African sales generated total proceeds of $3.0 billion.
The following table presents the gains on the African
divestiture transactions by year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
Net of
|
|
|
|
|
|
Net of
|
|
|
|
|
|
Net of
|
|
|
|
Gross
|
|
|
Taxes
|
|
|
Gross
|
|
|
Taxes
|
|
|
Gross
|
|
|
Taxes
|
|
|
|
(In millions)
|
|
|
Egypt
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
90
|
|
|
$
|
90
|
|
Equatorial Guinea
|
|
|
|
|
|
|
|
|
|
|
619
|
|
|
|
544
|
|
|
|
|
|
|
|
|
|
Gabon
|
|
|
|
|
|
|
|
|
|
|
117
|
|
|
|
122
|
|
|
|
|
|
|
|
|
|
Cote dIvoire
|
|
|
17
|
|
|
|
17
|
|
|
|
83
|
|
|
|
95
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
17
|
|
|
$
|
17
|
|
|
$
|
819
|
|
|
$
|
769
|
|
|
$
|
90
|
|
|
$
|
90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 vs. 2008 Earnings from discontinued operations
decreased $617 million in 2009. Our discontinued earnings
were impacted by several factors. First, operating revenues
declined largely due to a 36% decrease in the price realized on
our production, which was driven by a decline in crude oil index
prices. Second, both operating revenues and expenses declined
due to divestitures that closed in 2008. Discontinued earnings
also decreased due to $48 million of restructuring costs
that relate to our planned divestitures and were recognized in
the fourth quarter of 2009. These costs consist of employee
severance costs. Earnings also decreased $752 million in
2009 due to larger gains recognized on West African asset
divestitures in 2008.
Partially offsetting these decreased earnings in 2009 was the
larger reduction of carrying value recognized in 2008 compared
to 2009. The reductions largely consisted of full cost ceiling
limitations related to our assets in Brazil that were caused by
a decline in oil prices.
2008 vs. 2007 Earnings from discontinued operations
decreased $230 million in 2008. Our earnings were impacted
by several factors. First, operating revenues and expenses,
including the related production volumes, decreased largely due
to the timing of our 2008 and 2007 divestitures, partially
offset by the effects of first production in Brazil.
Discontinued earnings also decreased due to the net effect of
reductions in carrying value recognized in 2008 and 2007, which
largely related to our assets in Brazil. Discontinued earnings
increased $679 million in 2008 due to the larger African
divestiture gains in 2008.
52
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 2007 to 2009. The table presents
capital expenditures on a cash basis. Therefore, these amounts
differ from capital expenditure amounts that include accruals
and are referred to elsewhere in this document. Additional
discussion of these items follows the table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Sources of cash and cash equivalents:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating cash flow continuing operations
|
|
$
|
4,232
|
|
|
$
|
8,448
|
|
|
$
|
5,308
|
|
Sales of property and equipment
|
|
|
34
|
|
|
|
117
|
|
|
|
76
|
|
Net credit facility borrowings
|
|
|
|
|
|
|
|
|
|
|
1,450
|
|
Net commercial paper borrowings
|
|
|
1,431
|
|
|
|
1
|
|
|
|
|
|
Proceeds from debt issuance, net of commercial paper repayments
|
|
|
182
|
|
|
|
|
|
|
|
|
|
Net decrease in investments
|
|
|
7
|
|
|
|
250
|
|
|
|
202
|
|
Stock option exercises
|
|
|
42
|
|
|
|
116
|
|
|
|
91
|
|
Proceeds from exchange of Chevron stock
|
|
|
|
|
|
|
280
|
|
|
|
|
|
Cash distributed from discontinued operations
|
|
|
|
|
|
|
1,898
|
|
|
|
|
|
Other
|
|
|
8
|
|
|
|
59
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sources of cash and cash equivalents
|
|
|
5,936
|
|
|
|
11,169
|
|
|
|
7,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(4,879
|
)
|
|
|
(8,843
|
)
|
|
|
(5,709
|
)
|
Net credit facility repayments
|
|
|
|
|
|
|
(1,450
|
)
|
|
|
|
|
Net commercial paper repayments
|
|
|
|
|
|
|
|
|
|
|
(804
|
)
|
Debt repayments
|
|
|
(178
|
)
|
|
|
(1,031
|
)
|
|
|
(567
|
)
|
Repurchases of common stock
|
|
|
|
|
|
|
(665
|
)
|
|
|
(326
|
)
|
Redemption of preferred stock
|
|
|
|
|
|
|
(150
|
)
|
|
|
|
|
Dividends
|
|
|
(284
|
)
|
|
|
(289
|
)
|
|
|
(259
|
)
|
Other
|
|
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total uses of cash and cash equivalents
|
|
|
(5,358
|
)
|
|
|
(12,428
|
)
|
|
|
(7,665
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) from continuing operations
|
|
|
578
|
|
|
|
(1,259
|
)
|
|
|
(495
|
)
|
Increase from discontinued operations, net of distributions to
continuing operations
|
|
|
6
|
|
|
|
386
|
|
|
|
1,061
|
|
Effect of foreign exchange rates
|
|
|
43
|
|
|
|
(116
|
)
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
$
|
627
|
|
|
$
|
(989
|
)
|
|
$
|
617
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
1,011
|
|
|
$
|
384
|
|
|
$
|
1,373
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments at end of year
|
|
$
|
|
|
|
$
|
|
|
|
$
|
372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53
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 2009. Changes in operating cash flow from our
continuing operations 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 decreased 50%
during 2009 primarily due to the significant decrease in oil,
gas and NGL sales, net of commodity hedge settlements, as
discussed in the Results of Operations section of
this report.
During 2009, our operating cash flow funded approximately 87% of
our cash payments for capital expenditures. Commercial paper
borrowings were used to fund the remainder of our cash-based
capital expenditures. During 2008 and 2007 our capital
expenditures were primarily funded by our operating cash flow
and pre-existing cash balances.
Other
Sources of Cash Continuing and Discontinued
Operations
As needed, we supplement our operating cash flow with cash on
hand and access to our available credit under our credit
facilities and commercial paper program. We may also issue
long-term debt to supplement our operating cash flow while
maintaining adequate liquidity under our credit facilities.
Additionally, we sometimes acquire short-term investments to
maximize our income on available cash balances. As needed, we
may reduce our investment balances to further supplement our
operating cash flow.
In January 2009, we issued $500 million of
5.625% senior unsecured notes due January 15, 2014 and
$700 million of 6.30% senior unsecured notes due
January 15, 2019. The net proceeds received of
$1.187 billion, after discounts and issuance costs, were
used primarily to repay Devons $1.005 billion of
outstanding commercial paper as of December 31, 2008.
Subsequent to the $1.0 billion commercial paper repayment
in January 2009, we utilized additional commercial paper
borrowings of $1.4 billion to fund capital expenditure and
dividend payments in excess of our operating cash flow during
2009.
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 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.
54
Capital
Expenditures
Following are the components of our capital expenditures for the
years ended 2009, 2008 and 2007. The amounts in the table below
reflect cash payments for capital expenditures, including cash
paid for capital expenditures incurred. Capital expenditures
actually incurred during 2009, 2008 and 2007 were approximately
$4.7 billion, $10.0 billion and $5.9 billion,
respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
U.S. Onshore
|
|
$
|
2,413
|
|
|
$
|
5,606
|
|
|
$
|
3,280
|
|
Canada
|
|
|
1,064
|
|
|
|
1,459
|
|
|
|
1,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North American Onshore
|
|
|
3,477
|
|
|
|
7,065
|
|
|
|
4,512
|
|
U.S. Offshore
|
|
|
845
|
|
|
|
1,157
|
|
|
|
687
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exploration and development
|
|
|
4,322
|
|
|
|
8,222
|
|
|
|
5,199
|
|
Midstream
|
|
|
323
|
|
|
|
451
|
|
|
|
370
|
|
Other
|
|
|
234
|
|
|
|
170
|
|
|
|
141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total continuing operations
|
|
$
|
4,879
|
|
|
$
|
8,843
|
|
|
$
|
5,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
$4.3 billion, $8.2 billion and $5.2 billion in
2009, 2008 and 2007, respectively. The decrease in capital
expenditures from 2008 to 2009 was due to decreased drilling
activities in most of our operating areas in response to lower
commodity prices in 2009 compared to recent years. The 2008
capital expenditures include $2.6 billion related to
acquisitions of properties in Texas, Louisiana, Oklahoma and
Canada. Excluding the effect of the 2008 acquisitions, the
increase in capital expenditures from 2007 to 2008 was due to
increased drilling activities in the Barnett Shale, Gulf of
Mexico, Carthage, Groesbeck and Washakie areas of the United
States and the Lloydminster and Jackfish projects in Canada.
Expenditures in the first half of 2008 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 2007 to 2009 were related to
development activities in the Barnett Shale, the Arkoma-Woodford
Shale in southeastern Oklahoma, the Cana-Woodford Shale in
western Oklahoma and Jackfish in Canada.
Net
Repayments of Debt
Debt repayments in 2009 include the retirement of
$177 million of 10.125% notes upon maturity in the
fourth quarter.
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
55
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.
Repurchases
of Common Stock
During 2008 and 2007, we repurchased 10.6 million shares at
a total cost of $1.0 billion, or an average of $93.76 per
share, under approved repurchase programs. No shares were
repurchased in 2009. The following table summarizes our
repurchases under approved plans during 2008 and 2007 (amounts
and shares in millions). Both programs expired on
December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
Repurchase Program
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
$
|
665
|
|
|
|
6.5
|
|
|
$
|
102.56
|
|
|
$
|
326
|
|
|
|
4.1
|
|
|
$
|
79.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
Dividends
Our common stock dividends were $284 million (or a
quarterly rate of $0.16 per share) in both 2009 and 2008, and
$249 million (or a quarterly rate of $0.14) in 2007. Common
dividends increased from 2007 to 2008 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 2007.
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. 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, as well as our automatically effective
registration statement on
Form S-3ASR
filed with the SEC. This registration statement can be used to
offer short-term and long-term debt securities. In 2010, another
major source of liquidity will be proceeds from the sales of our
offshore operations, which we estimate will range from
$4.5 billion to $7.5 billion after taxes. 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 is sensitive to many variables, the most
volatile of which is pricing of the oil, natural gas and NGLs we
produce. Due to sharp declines in commodity prices, our
operating cash flow decreased approximately 50% to
$4.7 billion in 2009 as compared to 2008. In spite of the
recent commodity price declines, we expect operating cash flow
will continue to be a primary source of liquidity, and we will
need to manage our capital expenditures and other cash uses
accordingly. However, as a result of depressed commodity prices,
debt borrowings have been a significant source of liquidity
during 2009. During 2009, our net borrowings of long-term debt
and commercial paper totaled $1.6 billion. We anticipate
utilizing commercial paper borrowings as needed to supplement
operating cash flow in 2010. As the offshore divestiture
transactions close, we anticipate using a portion of the
proceeds to repay our commercial paper borrowings.
56
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. We expect this volatility to continue throughout 2010.
To mitigate some of the risk inherent in prices, we have
utilized various price swap, fixed-price physical delivery and
price collar contracts to set minimum and maximum prices on our
2010 production. As of February 15, 2010 approximately 65%
of our estimated 2010 oil production is subject to price collars
and approximately 54% of our estimated 2010 gas production is
subject to price collars, price swaps and fixed-price physicals.
We also have basis swaps associated with 0.2 Bcf per day of
our 2010 gas production.
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
February 15, 2010, we had total debt of $7.1 billion
with an overall weighted average borrowing rate of 5.93%. To
manage our exposure to interest rate volatility, we have
interest rate swap instruments with a total notional amount of
$1.85 billion. These consist of instruments with a notional
amount of $1.15 billion in which we receive a fixed rate
and pay a variable rate. The remaining instruments consist of
forward starting swaps. Under the terms of the forward starting
swaps, we will net settle these contracts in September 2011, or
sooner should we elect, based upon us paying a fixed rate and
receiving a floating rate. Including the effects of these swaps,
the weighted-average interest rate related to our fixed-rate
debt was 5.36% as of February 15, 2010.
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, posting of letters of credit,
prepayment requirements and collateral posting requirements.
Credit
Availability
We have two revolving lines of credit and a commercial paper
program which we can access to provide liquidity.
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 February 15, 2010, there were no borrowings
under the Senior Credit Facility.
We also have a $700 million
364-day,
syndicated, unsecured revolving senior credit facility (the
Short-Term Facility) that matures on
November 2, 2010. On the maturity date, all amounts
outstanding will be due
57
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 February 15, 2010, 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 February 15,
2010, we had $1.3 billion of commercial paper debt
outstanding at an average rate of 0.25%.
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,
2009, we were in compliance with this covenant. Our
debt-to-capitalization
ratio at December 31, 2009, as calculated pursuant to the
terms of the agreement, was 20.5%.
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 February 15, 2010 (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 2, 2010 maturity
|
|
|
700
|
|
|
|
|
|
|
Total credit facilities
|
|
|
3,350
|
|
Less:
|
|
|
|
|
Outstanding credit facility borrowings
|
|
|
|
|
Outstanding commercial paper borrowings
|
|
|
1,257
|
|
Outstanding letters of credit
|
|
|
88
|
|
|
|
|
|
|
Total available capacity
|
|
$
|
2,005
|
|
|
|
|
|
|
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.
58
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, 2009, we were not aware of any potential
ratings downgrades being contemplated by the rating agencies.
Capital
Expenditures
Our 2010 capital expenditures are expected to range from
$6.0 billion to $6.8 billion, including amounts
related to our discontinued operations. 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
2010 capital expenditures until later periods, or accelerate
capital expenditures planned for periods beyond 2010 to achieve
the desired balance between sources and uses of liquidity. The
amount and timing of the planned offshore asset divestitures in
2010 could also result in acceleration of capital spending on
our North American Onshore opportunities. Based upon current
price expectations for 2010 and the commodity hedging contracts
we have in place, we anticipate having adequate capital
resources to fund our 2010 capital expenditures.
Common
Stock Repurchase Programs
All of our common stock repurchase programs expired on
December 31, 2009. None of our programs were extended to
2010.
Contractual
Obligations
A summary of our contractual obligations as of December 31,
2009, 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)
|
|
|
North American Onshore:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt(1)
|
|
$
|
7,267
|
|
|
$
|
1,432
|
|
|
$
|
2,110
|
|
|
$
|
500
|
|
|
$
|
3,225
|
|
Interest expense(2)
|
|
|
4,998
|
|
|
|
406
|
|
|
|
666
|
|
|
|
508
|
|
|
|
3,418
|
|
Drilling and facility obligations(3)
|
|
|
1,136
|
|
|
|
659
|
|
|
|
395
|
|
|
|
81
|
|
|
|
1
|
|
Firm transportation agreements(4)
|
|
|
1,939
|
|
|
|
298
|
|
|
|
508
|
|
|
|
419
|
|
|
|
714
|
|
Asset retirement obligations(5)
|
|
|
1,068
|
|
|
|
44
|
|
|
|
115
|
|
|
|
150
|
|
|
|
759
|
|
Lease obligations(6)
|
|
|
347
|
|
|
|
57
|
|
|
|
94
|
|
|
|
49
|
|
|
|
147
|
|
Other(7)
|
|
|
518
|
|
|
|
129
|
|
|
|
128
|
|
|
|
57
|
|
|
|
204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North American Onshore
|
|
|
17,273
|
|
|
|
3,025
|
|
|
|
4,016
|
|
|
|
1,764
|
|
|
|
8,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Offshore:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and facility obligations(3)
|
|
|
2,113
|
|
|
|
955
|
|
|
|
775
|
|
|
|
383
|
|
|
|
|
|
Asset retirement obligations(5)
|
|
|
554
|
|
|
|
51
|
|
|
|
141
|
|
|
|
61
|
|
|
|
301
|
|
Lease obligations(6)
|
|
|
602
|
|
|
|
121
|
|
|
|
182
|
|
|
|
176
|
|
|
|
123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Offshore
|
|
|
3,269
|
|
|
|
1,127
|
|
|
|
1,098
|
|
|
|
620
|
|
|
|
424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grand Total
|
|
$
|
20,542
|
|
|
$
|
4,152
|
|
|
$
|
5,114
|
|
|
$
|
2,384
|
|
|
$
|
8,892
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59
|
|
|
(1) |
|
Debt amounts represent scheduled maturities of our debt
obligations at December 31, 2009, excluding
$12 million of net premiums included in the carrying value
of debt. |
|
(2) |
|
Interest expense related to our fixed-rate debt represents the
scheduled cash payments. Interest related to our variable-rate
commercial paper borrowings was estimated based upon expected
future interest rates as of December 31, 2009. |
|
(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 $2.1 billion of offshore obligations is
$1.4 billion that relates to long-term contracts for three
deepwater drilling rigs and certain other contracts for offshore
drilling and facility obligations in which drilling or
facilities construction has not commenced. The $1.4 billion
represents the gross commitment under these contracts. Our
ultimate payment for these commitments will be reduced by any
amounts billed to our working interest partners until we sell
the associated offshore properties. Payments for these
commitments, net of amounts billed to partners, will be
capitalized as a component of oil and gas properties. |
|
|
|
Additionally, our commitment under these contracts may be
further reduced if the buyers of our offshore assets assume all
or a portion of the obligations. If the buyers do not assume
these obligations, we will attempt to sublease the rigs to
reduce our commitment. However, if the buyers do not assume the
obligations and we are not able to sublease the rigs, we would
be contractually committed to the amounts related to the
remaining lease periods.
|
|
|
|
(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, 2009 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 2018. The Polvo FPSO lease term expires in
2014. The Cascade FPSO lease term expires in 2015. We expect the
eventual buyers of these offshore assets will assume the FPSO
leases. However, the amounts in the table reflect our full
commitments under the leases.
|
|
|
|
(7) |
|
These amounts include $272 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 $448 million and
$501 million at December 31, 2009 and 2008,
60
respectively. A detailed reconciliation of the 2009 changes to
our underfunded status is included in Note 8 to the
accompanying consolidated financial statements. Of the
$448 million underfunded status at the end of 2009,
$215 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, 2009, these
trusts had investments with a fair value of $39 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 $164 million at
December 31, 2009. 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. While we did have
investment gains in 2009, the investment losses experienced
during 2008 significantly reduced the value of our plans
assets. We estimate we will contribute approximately
$25 million to our qualified pension plans during 2010.
However, actual contributions may be different than this amount.
Our funding policy regarding the nonqualified defined benefit
plans is to supplement as needed the amounts accumulated in the
related trusts with available cash and cash equivalents.
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 $119 million, $61 million and
$41 million in 2009, 2008 and 2007, respectively. We
estimate that our pension expense will approximate
$85 million in 2010. Should our actual 2010 contributions
to qualified and nonqualified plans vary significantly from our
current estimate of $34 million, our actual 2010 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 7.18% and 8.40% at
December 31, 2009 and 2008, 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, 2009, the
target allocations for plan assets were 47.5% for equity
securities, 40% for fixed-income securities and 12.5% for other
investment types. Equity securities consist of investments in
large capitalization and small capitalization companies, both
domestic and international. Fixed-income securities include
corporate bonds of investment-grade companies from diverse
industries, United States Treasury obligations and asset-backed
securities. Other investment types include short-term investment
funds and a hedge fund of funds. 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 would increase the expected
2010 pension expense by $5 million.
We discounted our future pension obligations using a weighted
average rate of 6.00% at December 31, 2009 and 2008. 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.
61
The pension liability and future pension expense both increase
as the discount rate is reduced. Lowering the discount rate by
25 basis points would increase our pension liability at
December 31, 2009, by $32 million, and increase
estimated 2010 pension expense by $4 million.
At December 31, 2009, we had net actuarial losses of
$334 million, which will be recognized as a component of
pension expense in future years. These losses are primarily due
to investment losses on plan assets in 2008, reductions in the
discount rate since 2001 and increases in participant wages. We
estimate that approximately $27 million and
$23 million of the unrecognized actuarial losses will be
included in pension expense in 2010 and 2011, respectively. The
$27 million estimated to be recognized in 2010 is a
component of the total estimated 2010 pension expense of
$85 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 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. 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.
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
62
are prepared or audited by outside petroleum consultants, while
other reserve estimates are prepared by our engineers. See
Note 22 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 future net revenues are calculated using
prices that represent the average of the
first-day-of-the-month
price for the
12-month
period prior to the end of each quarterly period. Costs included
in future net revenues are determined in a similar manner.
Therefore, the future net revenues associated with the estimated
proved reserves are not based on our assessment of future prices
or costs. 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 calculated average price is adjusted
using the contract prices for such hedges. None of our
outstanding derivative contracts at December 31, 2009
qualified for hedge accounting treatment.
Because the ceiling calculation dictates the use of prices that
are not representative of future prices 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 cyclical and, for any particular
12-month
period, can be either higher or lower than our long-term price
forecast, which is a more appropriate input for estimating 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.
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 oil and gas derivative financial
instruments include financial price swaps, basis swaps and
costless price collars. Additionally, we periodically enter into
interest rate swaps to manage our exposure to interest rate
volatility. Under the terms of certain of our interest-rate
swaps, we receive a fixed rate and pay a variable rate on a
total notional amount. The remainder of our swaps represent
forward starting swaps, under which we will pay a fixed rate and
receive a floating 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
63
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 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
2009, 2008 and 2007, 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. 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.
We periodically 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 twelve separate counterparties, and our interest rate
derivative contracts are held with seven 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
mark-to-market
exposure 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, 2009, the credit
ratings of all our counterparties were investment grade.
Because we have chosen not to qualify our derivatives for hedge
accounting treatment, changes in the fair values of derivatives
can have a significant impact on our results of operations.
Generally, changes in derivative fair values 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
64
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.
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
dictates the use of prices that are not representative of future
prices. 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
65
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 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.
66
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 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, which we conduct as of October 31
each year, requires us to estimate the fair values of our own
assets and liabilities. Because quoted market prices are not
available for our 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. At October 31, 2009, the fair values of our
United States and Canadian reporting units were more than double
their related carrying values. This excess largely results from
the reductions of carrying value that we recognized in 2008 and
2009 due to full cost ceiling limitations, which are not
representative of the fair values of our oil and gas properties.
Excluding the effects of these reductions, the fair values of
our United States and Canadian reporting units exceeded the
carrying values by approximately 40% and 80%, respectively.
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.
Forward-Looking
Estimates
We are providing our 2010 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, 2009 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 2010 will be
substantially similar to those that existed in 2009, 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 an estimated average 2010
exchange rate of $0.95 U.S. dollar to $1.00 Canadian dollar.
We plan to strategically reposition Devon by divesting our
U.S. Offshore and International assets. We have entered
into agreements to sell our interests in the Cascade, Jack and
St. Malo properties in the Gulf of
67
Mexico. The following estimates assume these transactions close
on the expected dates during the first quarter of 2010. Although
we expect to complete the remainder of the divestitures
throughout 2010, all estimates presented assume the remaining
divestitures close at the end of 2010.
Operating
Items
Oil, Gas
and NGL Production
Set forth below are our estimates of oil, gas and NGL production
for 2010. We estimate that our combined oil, gas and NGL
production will total approximately 231 to 235 MMBoe. The
following estimates for oil, gas and NGL production are
calculated at the midpoint of the estimated range for total
production.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGLs
|
|
|
Total
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBoe)
|
|
|
U.S. Onshore
|
|
|
13
|
|
|
|
692
|
|
|
|
28
|
|
|
|
156
|
|
Canada
|
|
|
28
|
|
|
|
204
|
|
|
|
3
|
|
|
|
65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North American Onshore
|
|
|
41
|
|
|
|
896
|
|
|
|
31
|
|
|
|
221
|
|
U.S. Offshore
|
|
|
4
|
|
|
|
46
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
45
|
|
|
|
942
|
|
|
|
31
|
|
|
|
233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
Gas Prices
We expect our 2010 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
prices are exclusive of the anticipated effects of the financial
contracts presented in the Commodity Price Risk
Management section below.
The NYMEX price for oil is determined using 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 using 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
|
|
U.S. Onshore
|
|
90% to 100%
|
|
75% to 85%
|
Canada
|
|
65% to 75%
|
|
85% to 95%
|
North American Onshore
|
|
72% to 82%
|
|
77% to 87%
|
U.S. Offshore
|
|
95% to 105%
|
|
100% to 110%
|
Commodity
Price Risk Management
From time to time, we enter into NYMEX related financial
commodity collar, price swap and basis 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 2010.
As of February 15, 2010, our financial commodity contracts
pertaining to 2010 consisted of oil and gas price collars, gas
price swaps and gas basis swaps. The key terms of these
contracts are presented in the following tables.
|
|
|
|
|
|
|
|
|
|
|
Gas Price Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
Volume
|
|
|
Average Price
|
|
Period
|
|
(MMBtu/d)
|
|
|
($/MMBtu)
|
|
|
Total year
|
|
|
1,265,000
|
|
|
$
|
6.16
|
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Basis Swaps
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
|
|
Differential to
|
|
|
|
|
|
Volume
|
|
|
Henry Hub
|
|
Period
|
|
Index
|
|
(MMBtu/d)
|
|
|
($/MMBtu)
|
|
|
Total year
|
|
AECO
|
|
|
150,000
|
|
|
$
|
0.33
|
|
Total year
|
|
CIG
|
|
|
70,000
|
|
|
$
|
0.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Price Collars
|
|
|
|
|
|
|
Floor Price
|
|
|
Ceiling Price
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
Volume
|
|
|
Floor Range
|
|
|
Average Price
|
|
|
Ceiling Range
|
|
|
Average Price
|
|
Period
|
|
(MMBtu/d)
|
|
|
($/MMBtu/d)
|
|
|
($/MMBtu/d)
|
|
|
($/MMBtu/d)
|
|
|
($/MMBtu/d)
|
|
|
First Quarter
|
|
|
70,000
|
|
|
$
|
5.40 - $5.40
|
|
|
$
|
5.40
|
|
|
$
|
6.01 - $6.14
|
|
|
$
|
6.06
|
|
Second Quarter
|
|
|
95,000
|
|
|
$
|
5.50 - $5.50
|
|
|
$
|
5.50
|
|
|
$
|
6.80 - $7.10
|
|
|
$
|
6.94
|
|
Third Quarter
|
|
|
95,000
|
|
|
$
|
5.50 - $5.50
|
|
|
$
|
5.50
|
|
|
$
|
6.80 - $7.10
|
|
|
$
|
6.94
|
|
Fourth Quarter
|
|
|
95,000
|
|
|
$
|
5.50 - $5.50
|
|
|
$
|
5.50
|
|
|
$
|
6.80 - $7.10
|
|
|
$
|
6.94
|
|
Total year
|
|
|
88,836
|
|
|
$
|
5.40 - $5.50
|
|
|
$
|
5.48
|
|
|
$
|
6.01 - $7.10
|
|
|
$
|
6.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Price Collars
|
|
|
|
|
|
|
Floor Price
|
|
|
Ceiling Price
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
Volume
|
|
|
Floor Range
|
|
|
Average Price
|
|
|
Ceiling Range
|
|
|
Average Price
|
|
Period
|
|
(Bbls/d)
|
|
|
($/Bbl)
|
|
|
($/Bbl)
|
|
|
($/Bbl)
|
|
|
($/Bbl)
|
|
|
Total year
|
|
|
79,000
|
|
|
$
|
65.00 - $70.00
|
|
|
$
|
67.47
|
|
|
$
|
90.35 - $103.30
|
|
|
$
|
96.48
|
|
To the extent that monthly NYMEX prices or differentials on
certain regional indexes in 2010 are outside of the ranges
established by the collars or differ from those established by
the swaps, we and the counterparties to the contracts will
cash-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 2010.
Changes in the contracts fair values will also be recorded
as increases or decreases to our revenues. The expected ranges
of our realized prices as a percentage of NYMEX prices, which
are presented earlier in this report, do not include any
estimates of the impact on our prices from monthly settlements
or changes in the fair values of our price collars and swaps.
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 2010 marketing and
midstream operating profit will be between $450 million and
$525 million. We estimate that marketing and midstream
revenues will be between $1.850 billion and
$2.125 billion, and marketing and midstream expenses will
be between $1.400 billion and $1.600 billion.
Lease
Operating Expenses
These expenses, which include transportation costs, 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. Oil, gas and NGL prices
also have an effect on lease operating expenses and impact the
economic feasibility of planned workover projects.
69
Given these uncertainties, we expect that our 2010 lease
operating expenses will be between $1.74 billion and
$1.90 billion. This estimated range includes
$1.58 billion to $1.72 billion related to our North
American Onshore business and $0.16 to $0.18 billion
associated with our U.S. Offshore operations.
Taxes
Other Than Income Taxes
Our taxes other than income taxes primarily consist of
production taxes and ad valorem taxes that relate to our
U.S. Onshore properties and are assessed by various
government agencies. Production taxes are based on a percentage
of production revenues that varies by property and government
jurisdiction. Ad valorem taxes generally are based on property
values as determined by the government agency assessing the tax.
Over time, a certain propertys assessed value will
increase or decrease due to changes in commodity sales prices,
production volumes and proved reserves. Therefore, ad valorem
taxes will generally move in the same direction as our oil, gas
and NGL sales but in a less predictable manner compared to
production taxes. Additionally, both production and ad valorem
taxes will increase or decrease due to changes in the rates
assessed by the government agencies.
Given these uncertainties, we estimate that our taxes other than
income taxes for 2010 will be between 4.50% and 5.50% of total
oil, gas and NGL sales. We estimate our 2010 taxes other than
income taxes for our North American Onshore operations will
range from 4.75% to 5.75% of revenues. We estimate the
U.S. Offshore rates will range from 1.00% to 2.00% of
revenues.
Depreciation,
Depletion and Amortization (DD&A)
Our 2010 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 2010 compared to the costs incurred for
such efforts, revisions to our year-end 2009 reserve estimates
that, based on prior experience, are likely to be made during
2010, as well as reductions of carrying value resulting from
full cost ceiling tests.
Given these uncertainties, we estimate that our oil and gas
property related DD&A rate will be between $7.60 per Boe
and $8.10 per Boe. Based on these DD&A rates and the
production estimates set forth earlier, oil and gas property
related DD&A expense for 2010 is expected to be between
$1.77 billion and $1.89 billion.
For our North American Onshore assets, we estimate the DD&A
rate will range from $7.65 to $8.15 per Boe, resulting in
estimated DD&A expense of $1.69 billion to
$1.80 billion. Our U.S. Offshore DD&A rate is
estimated to be between $6.75 and $7.25 per Boe, resulting in
estimated DD&A expense of $0.08 billion to
$0.09 billion.
Additionally, we expect that our depreciation and amortization
expense related to non-oil and gas property fixed assets will
total between $270 million and $300 million in 2010.
This estimate relates entirely to our North American Onshore
assets.
Accretion
of Asset Retirement Obligation
Accretion of asset retirement obligation in 2010 is expected to
be between $95 million and $105 million. This
estimated range includes $70 million to $80 million
related to our North American Onshore business and
$25 million associated with our U.S. Offshore
operations.
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
70
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 2010 will
be between $580 million and $620 million. This
estimate includes approximately $115 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.
Restructuring
Costs
In conjunction with the planned 2010 asset divestitures, we
estimate we will incur certain one-time restructuring costs
totaling between $203 million and $273 million. Such
costs estimates consist of employee severance and termination
costs, contract termination costs and other associated costs. We
recognized $153 million of employee severance costs during
the fourth quarter of 2009. We expect the majority of the
remaining restructuring costs, including any revisions to the
fourth quarter 2009 employee severance costs, will be
recognized during 2010.
Reduction
of Carrying Value of Oil and Gas Properties
Due to the volatile nature of oil and gas prices, it is not
possible to predict whether we will incur full cost writedowns
in 2010.
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 2010 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 that affect
outstanding debt balances and related interest expense, such as
the amount and timing of capital expenditures are generally
within our control.
As of February 15, 2010, we had total debt of
$7.1 billion. This included $5.8 billion of fixed-rate
debt and $1.3 billion of variable-rate commercial paper
borrowings. The fixed-rate debt bears interest at an overall
weighted average rate of 7.2%. 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 February 15,
2010, the weighted average variable rate for our commercial
paper borrowings was 0.25%. 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 2010 interest expense
to be between $325 million and $365 million. The
estimated interest expense is exclusive of the anticipated
effects of the interest rate swap contracts presented in the
Interest Rate Risk Management section below.
The 2010 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 2010 related to our fixed-rate
and floating-rate debt, including net accretion of related
discounts, to be between $395 million and
$435 million. We expect the interest expense in 2010
related to facility and agency fees, amortization of debt
issuance costs and other miscellaneous items not related to
outstanding debt balances to be between $10 million and
$20 million. We also expect to capitalize between
$80 million and $90 million of interest
during 2010.
Interest
Rate Risk Management
From time to time, we enter into interest rate swaps. Such
contracts are used to manage our exposure to interest rate
volatility.
71
As of February 15, 2010, our interest rate swaps pertaining
to 2010 consist of instruments with a notional amount of
$1.15 billion in which we receive a fixed rate and pay a
variable rate. The key terms of these contracts are presented in
the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Rate
|
|
|
Variable
|
|
|
|
Notional
|
|
|
Received
|
|
|
Rate Paid
|
|
Expiration
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
$
|
300
|
|
|
|
4.30
|
%
|
|
Six month LIBOR
|
|
|
July 18, 2011
|
|
$
|
100
|
|
|
|
1.90
|
%
|
|
Federal funds rate
|
|
|
August 3, 2012
|
|
$
|
500
|
|
|
|
3.90
|
%
|
|
Federal funds rate
|
|
|
July 18, 2013
|
|
$
|
250
|
|
|
|
3.85
|
%
|
|
Federal funds rate
|
|
|
July 22, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,150
|
|
|
|
3.82
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
Our financial income tax rate in 2010 will vary materially
depending on the actual amount of financial pre-tax earnings.
The tax rate for 2010 will be significantly affected by the
proportional share of consolidated pre-tax earnings generated by
our United States and Canadian operations due to the different
tax rates of each country. Also, certain tax deductions and
credits will have a fixed impact on 2010 income tax expense
regardless of the level of pre-tax earnings that are produced.
Additionally, 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
these tax deductions and credits on 2010 financial income tax
rates.
Given the uncertainty of pre-tax earnings, we expect that our
total financial income tax rate in 2010 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%. These ranges do not include the impact of current
and deferred income taxes that will be recognized upon the
completion of the 2010 asset divestitures.
Discontinued
Operations
The following table shows the estimates for 2010 production,
pricing, expenses and capital associated with our discontinued
International operations for 2010. These estimates assume the
sales will occur at the end of 2010. Pursuant to accounting
rules for discontinued operations, the International assets will
not be subject to DD&A during 2010.
|
|
|
|
|
|
|
|
|
|
|
Low
|
|
|
High
|
|
|
|
($ in millions,
|
|
|
|
except per Boe)
|
|
|
Oil production (MMBbls)
|
|
|
14
|
|
|
|
16
|
|
Average oil price as a % of NYMEX
|
|
|
90
|
%
|
|
|
100
|
%
|
LOE
|
|
$
|
190
|
|
|
$
|
210
|
|
Taxes other than income taxes as % of revenue
|
|
|
10.25
|
%
|
|
|
11.25
|
%
|
Accretion of asset retirement obligation
|
|
$
|
5
|
|
|
$
|
5
|
|
Income tax rates:
|
|
|
|
|
|
|
|
|
Current
|
|
|
20
|
%
|
|
|
30
|
%
|
Deferred
|
|
|
(5
|
)%
|
|
|
|
%
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
15
|
%
|
|
|
30
|
%
|
|
|
|
|
|
|
|
|
|
Development capital
|
|
$
|
220
|
|
|
$
|
260
|
|
Exploration capital
|
|
$
|
240
|
|
|
$
|
280
|
|
|
|
|
|
|
|
|
|
|
Total development & exploration
|
|
$
|
460
|
|
|
$
|
540
|
|
|
|
|
|
|
|
|
|
|
Other capital
|
|
$
|
80
|
|
|
$
|
90
|
|
72
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 forecast, 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 2010 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 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
North American
|
|
|
U.S.
|
|
|
|
|
|
|
Onshore
|
|
|
Canada
|
|
|
Onshore
|
|
|
Offshore
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Development capital
|
|
$
|
2,210-$2,470
|
|
|
$
|
1,010-$1,140
|
|
|
$
|
3,220-$3,610
|
|
|
$
|
420-$500
|
|
|
$
|
3,640-$4,110
|
|
Exploration capital
|
|
$
|
520-$560
|
|
|
$
|
20-$30
|
|
|
$
|
540-$590
|
|
|
$
|
100-$120
|
|
|
$
|
640-$710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,730-$3,030
|
|
|
$
|
1,030-$1,170
|
|
|
$
|
3,760-$4,200
|
|
|
$
|
520-$620
|
|
|
$
|
4,280-$4,820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In addition to the above expenditures for drilling, development
and facilities, we expect to capitalize between
$330 million and $350 million of G&A expenses in
accordance with the full cost method of accounting and to
capitalize between $45 million and $55 million of
interest. We also expect to pay between $80 million and
$90 million for plugging and abandonment charges.
Additionally, we expect to spend between $380 million and
$430 million on our marketing and midstream assets, which
primarily include our oil pipelines, gas processing plants, and
gas pipeline systems. We expect to spend between
$385 million and $435 million for corporate and other
fixed assets.
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 447 million shares of common
stock outstanding as of December 31, 2009, dividends are
expected to approximate $286 million.
Capital
Resources and Liquidity
Our estimated 2010 cash uses, including our capital activities,
are expected to be funded primarily through a combination of our
existing cash balances and operating cash flow. Another major
source of liquidity will be proceeds from the divestiture of our
offshore operations, which we estimate will range from
$4.5 billion to $7.5 billion after taxes. The amount
of operating cash flow to be generated during 2010 is uncertain
due to the factors affecting revenues and expenses as previously
cited. The amount of divestiture proceeds we ultimately receive
is also uncertain. However, we expect our combined capital
resources will be adequate to fund our anticipated capital
expenditures and other cash uses for 2010. Additionally, we can
borrow commercial paper or access our lines of credit, which had
an available capacity of approximately $2.0 billion as of
February 15, 2010, to fund planned or additional capital
activities.
73
|
|
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.
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. Consequently, 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,
basis swaps and costless price collars.
Based on gas price contracts in place as of December 31,
2009, we have approximately 1.3 Bcf per day of gas
production in 2010 that is associated with price swaps or
fixed-price contracts. This amount represents approximately 50%
of our estimated 2010 gas production. As of December 31,
2009, we also have basis swaps associated with 0.2 Bcf per
day of our 2010 gas production. All of the gas price swap
contracts expire December 31, 2010. The key terms of our
gas price contracts are presented in the following tables.
|
|
|
|
|
|
|
|
|
|
|
2010 Gas Price Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
Volume
|
|
|
Average Price
|
|
Period
|
|
(MMBtu/d)
|
|
|
($/MMBtu)
|
|
|
Total year
|
|
|
1,265,000
|
|
|
$
|
6.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Gas Basis Swaps
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
|
|
Differential
|
|
|
|
|
|
Volume
|
|
|
to Henry Hub
|
|
Period
|
|
Index
|
|
(MMBtu/d)
|
|
|
($/MMBtu)
|
|
|
Total year
|
|
AECO
|
|
|
150,000
|
|
|
$
|
0.33
|
|
Total year
|
|
CIG
|
|
|
70,000
|
|
|
$
|
0.37
|
|
Based on oil price collar contracts in place as of
December 31, 2009, we have hedged 79,000 barrels of
oil per day for 2010. This amount represents approximately 65%
of our estimated 2010 oil production. The key terms of our oil
collar contracts are presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Oil Price Collars
|
|
|
|
|
|
|
Floor Price
|
|
|
Ceiling Price
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
Volume
|
|
|
Floor Range
|
|
|
Average Price
|
|
|
Ceiling Range
|
|
|
Average Price
|
|
Period
|
|
(Bbls/d)
|
|
|
($/Bbl)
|
|
|
($/Bbl)
|
|
|
($/Bbl)
|
|
|
($/Bbl)
|
|
|
Total year
|
|
|
79,000
|
|
|
$
|
65.00 - $70.00
|
|
|
$
|
67.47
|
|
|
$
|
90.35 - $103.30
|
|
|
$
|
96.48
|
|
The fair values of our gas price and basis swaps and oil collars
are largely determined by estimates of the forward curves of
relevant oil and gas price indexes. At December 31, 2009, a
10% increase in these forward curves would have decreased the
fair value of our gas price swaps by approximately
$264 million. A 10% increase in the forward curves
associated with our oil collars would have decreased the fair
value of these instruments by approximately $108 million.
74
Interest
Rate Risk
At December 31, 2009, we had debt outstanding of
$7.3 billion. Of this amount, $5.9 billion, or 80%,
bears interest at fixed rates averaging 7.2%. Additionally, we
had $1.4 billion of outstanding commercial paper, bearing
interest at floating rates which averaged 0.29%.
As of December 31, 2009, our interest rate swaps consisted
of instruments with a total notional amount of
$1.85 billion. These consist of instruments with a notional
amount of $1.15 billion in which we receive a fixed rate
and pay a variable rate. The remaining instruments consist of
forward starting swaps. Under the terms of the forward starting
swaps, we will net settle these contracts in September 2011, or
sooner should we elect. The net settlement amount will be based
upon us paying a weighted-average fixed rate of 3.99% and
receiving a floating rate that is based upon the three-month
LIBOR. The difference between the fixed and floating rate will
be applied to the notional amount for the
30-year
period from September 30, 2011 to September 30, 2041.
The key terms of these contracts are presented in the following
tables.
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-to-Floating Swaps
|
|
|
|
|
Fixed Rate
|
|
|
Variable
|
|
|
|
Notional
|
|
|
Received
|
|
|
Rate Paid
|
|
Expiration
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
$
|
300
|
|
|
|
4.30
|
%
|
|
Six month LIBOR
|
|
|
July 18, 2011
|
|
$
|
100
|
|
|
|
1.90
|
%
|
|
Federal funds rate
|
|
|
August 3, 2012
|
|
$
|
500
|
|
|
|
3.90
|
%
|
|
Federal funds rate
|
|
|
July 18, 2013
|
|
$
|
250
|
|
|
|
3.85
|
%
|
|
Federal funds rate
|
|
|
July 22, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,150
|
|
|
|
3.82
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward Starting Swaps
|
|
|
|
|
Fixed Rate
|
|
|
Variable
|
|
|
|
Notional
|
|
|
Paid
|
|
|
Rate Received
|
|
Expiration
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
$
|
700
|
|
|
|
3.99
|
%
|
|
Three month LIBOR
|
|
|
September 30, 2011
|
|
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, 2009, a 10% increase
in these forward curves would have increased our net assets by
approximately $46 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,
2009 balance sheet.
75
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED
FINANCIAL STATEMENT SCHEDULES
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
77
|
|
Consolidated Financial Statements
|
|
|
78
|
|
Consolidated Balance Sheets as of December 31, 2009 and 2008
|
|
|
78
|
|
Consolidated Statements of Operations for the Years Ended
December 31, 2009, 2008 and 2007
|
|
|
79
|
|
Consolidated Statements of Comprehensive (Loss) Income for the
Years Ended December 31, 2009, 2008 and 2007
|
|
|
80
|
|
Consolidated Statements of Stockholders Equity for the
Years Ended December 31, 2009, 2008 and 2007
|
|
|
81
|
|
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2009, 2008 and 2007
|
|
|
82
|
|
Notes to Consolidated Financial Statements
|
|
|
83
|
|
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.
76
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, 2009 and 2008, 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, 2009. We also
have audited Devon Energy Corporations internal control
over financial reporting as of December 31, 2009, 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, 2009 and 2008, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2009, 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, 2009, based on control
criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
KPMG LLP
Oklahoma City, Oklahoma
February 24, 2010
77
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions, except share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
646
|
|
|
$
|
195
|
|
Accounts receivable
|
|
|
1,208
|
|
|
|
1,300
|
|
Derivative financial instruments, at fair value
|
|
|
211
|
|
|
|
282
|
|
Current assets held for sale
|
|
|
657
|
|
|
|
392
|
|
Other current assets
|
|
|
270
|
|
|
|
515
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
2,992
|
|
|
|
2,684
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, at cost, based on the full cost method
of accounting
for oil and gas properties ($4,078 million and
$4,248 million excluded from
amortization in 2009 and 2008, respectively)
|
|
|
60,475
|
|
|
|
53,391
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
41,708
|
|
|
|
31,360
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
18,767
|
|
|
|
22,031
|
|
Goodwill
|
|
|
5,930
|
|
|
|
5,511
|
|
Long-term assets held for sale
|
|
|
1,250
|
|
|
|
1,128
|
|
Other long-term assets, including $246 million and
$199 million at fair value in
2009 and 2008, respectively
|
|
|
747
|
|
|
|
554
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
29,686
|
|
|
$
|
31,908
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable trade
|
|
$
|
1,137
|
|
|
$
|
1,612
|
|
Revenues and royalties due to others
|
|
|
486
|
|
|
|
490
|
|
Short-term debt
|
|
|
1,432
|
|
|
|
180
|
|
Current portion of asset retirement obligations, at fair value
|
|
|
95
|
|
|
|
138
|
|
Current liabilities associated with assets held for sale
|
|
|
234
|
|
|
|
365
|
|
Other current liabilities, including $38 million at fair
value in 2009
|
|
|
418
|
|
|
|
350
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
3,802
|
|
|
|
3,135
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
5,847
|
|
|
|
5,661
|
|
Asset retirement obligations, at fair value
|
|
|
1,418
|
|
|
|
1,249
|
|
Liabilities associated with assets held for sale, including
$109 million and $98
million at fair value in 2009 and 2008, respectively
|
|
|
213
|
|
|
|
166
|
|
Other long-term liabilities
|
|
|
937
|
|
|
|
1,023
|
|
Deferred income taxes
|
|
|
1,899
|
|
|
|
3,614
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock of $0.10 par value. Authorized
1.0 billion shares;
issued 446.7 million and 443.7 million shares in 2009
and 2008, respectively
|
|
|
45
|
|
|
|
44
|
|
Additional paid-in capital
|
|
|
6,527
|
|
|
|
6,257
|
|
Retained earnings
|
|
|
7,613
|
|
|
|
10,376
|
|
Accumulated other comprehensive income
|
|
|
1,385
|
|
|
|
383
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
15,570
|
|
|
|
17,060
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 10)
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
29,686
|
|
|
$
|
31,908
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
78
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions, except per share amounts)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales
|
|
$
|
6,097
|
|
|
$
|
11,720
|
|
|
$
|
8,225
|
|
Net gain (loss) on oil and gas derivative financial instruments
|
|
|
384
|
|
|
|
(154
|
)
|
|
|
14
|
|
Marketing and midstream revenues
|
|
|
1,534
|
|
|
|
2,292
|
|
|
|
1,736
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
8,015
|
|
|
|
13,858
|
|
|
|
9,975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
1,670
|
|
|
|
1,851
|
|
|
|
1,532
|
|
Taxes other than income taxes
|
|
|
314
|
|
|
|
476
|
|
|
|
358
|
|
Marketing and midstream operating costs and expenses
|
|
|
1,022
|
|
|
|
1,611
|
|
|
|
1,217
|
|
Depreciation, depletion and amortization of oil and gas
properties
|
|
|
1,832
|
|
|
|
2,948
|
|
|
|
2,412
|
|
Depreciation and amortization of non-oil and gas properties
|
|
|
276
|
|
|
|
255
|
|
|
|
201
|
|
Accretion of asset retirement obligations
|
|
|
91
|
|
|
|
80
|
|
|
|
70
|
|
General and administrative expenses
|
|
|
648
|
|
|
|
645
|
|
|
|
513
|
|
Restructuring costs
|
|
|
105
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
349
|
|
|
|
329
|
|
|
|
430
|
|
Change in fair value of other financial instruments
|
|
|
(106
|
)
|
|
|
149
|
|
|
|
(34
|
)
|
Reduction of carrying value of oil and gas properties
|
|
|
6,408
|
|
|
|
9,891
|
|
|
|
|
|
Other income, net
|
|
|
(68
|
)
|
|
|
(217
|
)
|
|
|
(51
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net
|
|
|
12,541
|
|
|
|
18,018
|
|
|
|
6,648
|
|
Earnings (loss) from continuing operations before income taxes
|
|
|
(4,526
|
)
|
|
|
(4,160
|
)
|
|
|
3,327
|
|
Income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
241
|
|
|
|
441
|
|
|
|
235
|
|
Deferred
|
|
|
(2,014
|
)
|
|
|
(1,562
|
)
|
|
|
607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit)
|
|
|
(1,773
|
)
|
|
|
(1,121
|
)
|
|
|
842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations
|
|
|
(2,753
|
)
|
|
|
(3,039
|
)
|
|
|
2,485
|
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income taxes
|
|
|
322
|
|
|
|
1,258
|
|
|
|
1,593
|
|
Discontinued operations income tax expense
|
|
|
48
|
|
|
|
367
|
|
|
|
472
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations
|
|
|
274
|
|
|
|
891
|
|
|
|
1,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
|
(2,479
|
)
|
|
|
(2,148
|
)
|
|
|
3,606
|
|
Preferred stock dividends
|
|
|
|
|
|
|
5
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) applicable to common stockholders
|
|
$
|
(2,479
|
)
|
|
$
|
(2,153
|
)
|
|
$
|
3,596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) from continuing operations per share
|
|
$
|
(6.20
|
)
|
|
$
|
(6.86
|
)
|
|
$
|
5.56
|
|
Basic earnings from discontinued operations per share
|
|
|
0.62
|
|
|
|
2.01
|
|
|
|
2.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net earnings (loss) per share
|
|
$
|
(5.58
|
)
|
|
$
|
(4.85
|
)
|
|
$
|
8.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) from continuing operations per share
|
|
$
|
(6.20
|
)
|
|
$
|
(6.86
|
)
|
|
$
|
5.50
|
|
Diluted earnings from discontinued operations per share
|
|
|
0.62
|
|
|
|
2.01
|
|
|
|
2.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net earnings (loss) per share
|
|
$
|
(5.58
|
)
|
|
$
|
(4.85
|
)
|
|
$
|
8.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
79
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Net earnings (loss)
|
|
$
|
(2,479
|
)
|
|
$
|
(2,148
|
)
|
|
$
|
3,606
|
|
Foreign currency translation:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cumulative translation adjustment
|
|
|
993
|
|
|
|
(1,960
|
)
|
|
|
1,389
|
|
Foreign currency translation income tax benefit (expense)
|
|
|
(62
|
)
|
|
|
79
|
|
|
|
(42
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation total
|
|
|
931
|
|
|
|
(1,881
|
)
|
|
|
1,347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial gain (loss) and prior service cost arising in
current year
|
|
|
59
|
|
|
|
(239
|
)
|
|
|
(90
|
)
|
Recognition of net actuarial loss and prior service cost in net
earnings (loss)
|
|
|
54
|
|
|
|
18
|
|
|
|
14
|
|
Curtailment of pension benefits
|
|
|
|
|
|
|
|
|
|
|
16
|
|
Pension and postretirement benefit plans income tax benefit
(expense)
|
|
|
(42
|
)
|
|
|
80
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit plans total
|
|
|
71
|
|
|
|
(141
|
)
|
|
|
(37
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification adjustment for realized gains included in net
earnings
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive earnings (loss), net of tax
|
|
|
1,002
|
|
|
|
(2,022
|
)
|
|
|
1,309
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
(1,477
|
)
|
|
$
|
(4,170
|
)
|
|
$
|
4,915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
80
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Other
|
|
|
|
|
|
Total
|
|
|
|
Preferred
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
Treasury
|
|
|
Stockholders
|
|
|
|
Stock
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Earnings
|
|
|
Income
|
|
|
Stock
|
|
|
Equity
|
|
|
|
(In millions)
|
|
|
Balance as of December 31, 2006
|
|
$
|
1
|
|
|
|
444
|
|
|
$
|
44
|
|
|
$
|
6,840
|
|
|
$
|
9,114
|
|
|
$
|
1,444
|
|
|
$
|
(1
|
)
|
|
$
|
17,442
|
|
Net earnings (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,606
|
|
|
|
|
|
|
|
|
|
|
|
3,606
|
|
Other comprehensive earnings (loss), net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,309
|
|
|
|
|
|
|
|
1,309
|
|
Other financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
364
|
|
|
|
(364
|
)
|
|
|
|
|
|
|
|
|
Uncertain income tax positions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11
|
)
|
|
|
|
|
|
|
|
|
|
|
(11
|
)
|
Pension and postretirement benefit plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 earnings (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,148
|
)
|
|
|
|
|
|
|
|
|
|
|
(2,148
|
)
|
Other comprehensive earnings (loss), net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,479
|
)
|
|
|
|
|
|
|
|
|
|
|
(2,479
|
)
|
Other comprehensive earnings (loss), net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,002
|
|
|
|
|
|
|
|
1,002
|
|
Stock option exercises
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
47
|
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
43
|
|
Restricted stock grants, net of cancellations
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock repurchased
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(40
|
)
|
|
|
(40
|
)
|
Common stock retired
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|
|
|
|
|
|
|
|
|
|
45
|
|
|
|
|
|
Common stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(284
|
)
|
|
|
|
|
|
|
|
|
|
|
(284
|
)
|
Share-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
260
|
|
Share-based compensation tax benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2009
|
|
|
|
|
|
|
447
|
|
|
$
|
45
|
|
|
$
|
6,527
|
|
|
$
|
7,613
|
|
|
$
|
1,385
|
|
|
$
|
|
|
|
$
|
15,570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
81
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
$
|
(2,479
|
)
|
|
$
|
(2,148
|
)
|
|
$
|
3,606
|
|
Net earnings from discontinued operations
|
|
|
(274
|
)
|
|
|
(891
|
)
|
|
|
(1,121
|
)
|
Adjustments to reconcile earnings (loss) from continuing
operations
|
|
|
|
|
|
|
|
|
|
|
|
|
to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
2,108
|
|
|
|
3,203
|
|
|
|
2,613
|
|
Deferred income tax expense (benefit)
|
|
|
(2,014
|
)
|
|
|
(1,562
|
)
|
|
|
607
|
|
Reduction of carrying value of oil and gas properties
|
|
|
6,408
|
|
|
|
9,891
|
|
|
|
|
|
Net unrealized loss (gain) on oil and gas derivative financial
instruments
|
|
|
121
|
|
|
|
(243
|
)
|
|
|
26
|
|
Other noncash charges
|
|
|
222
|
|
|
|
410
|
|
|
|
150
|
|
Net decrease (increase) in working capital
|
|
|
149
|
|
|
|
(207
|
)
|
|
|
(512
|
)
|
Decrease (increase) in long-term other assets
|
|
|
(6
|
)
|
|
|
(53
|
)
|
|
|
(60
|
)
|
Increase (decrease) in long-term other liabilities
|
|
|
(3
|
)
|
|
|
48
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities continuing
operations
|
|
|
4,232
|
|
|
|
8,448
|
|
|
|
5,308
|
|
Cash provided by operating activities discontinued
operations
|
|
|
505
|
|
|
|
960
|
|
|
|
1,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
4,737
|
|
|
|
9,408
|
|
|
|
6,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sales of property and equipment
|
|
|
34
|
|
|
|
117
|
|
|
|
76
|
|
Capital expenditures
|
|
|
(4,879
|
)
|
|
|
(8,843
|
)
|
|
|
(5,710
|
)
|
Proceeds from exchange of Chevron Corporation common stock
|
|
|
|
|
|
|
280
|
|
|
|
|
|
Purchases of short-term investments
|
|
|
|
|
|
|
(50
|
)
|
|
|
(934
|
)
|
Sales of long-term and short-term investments
|
|
|
7
|
|
|
|
300
|
|
|
|
1,136
|
|
Other
|
|
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities continuing
operations
|
|
|
(4,855
|
)
|
|
|
(8,196
|
)
|
|
|
(5,432
|
)
|
Cash provided by (used in) investing activities
discontinued operations
|
|
|
(499
|
)
|
|
|
1,323
|
|
|
|
(282
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(5,354
|
)
|
|
|
(6,873
|
)
|
|
|
(5,714
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from borrowings of long-term debt, net of issuance costs
|
|
|
1,187
|
|
|
|
|
|
|
|
|
|
Credit facility repayments
|
|
|
|
|
|
|
(3,191
|
)
|
|
|
(757
|
)
|
Credit facility borrowings
|
|
|
|
|
|
|
1,741
|
|
|
|
2,207
|
|
Net commercial paper borrowings (repayments)
|
|
|
426
|
|
|
|
1
|
|
|
|
(804
|
)
|
Debt repayments
|
|
|
(178
|
)
|
|
|
(1,031
|
)
|
|
|
(567
|
)
|
Redemption of preferred stock
|
|
|
|
|
|
|
(150
|
)
|
|
|
|
|
Proceeds from stock option exercises
|
|
|
42
|
|
|
|
116
|
|
|
|
91
|
|
Repurchases of common stock
|
|
|
|
|
|
|
(665
|
)
|
|
|
(326
|
)
|
Dividends paid on common and preferred stock
|
|
|
(284
|
)
|
|
|
(289
|
)
|
|
|
(259
|
)
|
Excess tax benefits related to share-based compensation
|
|
|
8
|
|
|
|
60
|
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
1,201
|
|
|
|
(3,408
|
)
|
|
|
(371
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash
|
|
|
43
|
|
|
|
(116
|
)
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
627
|
|
|
|
(989
|
)
|
|
|
617
|
|
Cash and cash equivalents at beginning of period (including cash
related to assets held for sale)
|
|
|
384
|
|
|
|
1,373
|
|
|
|
756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period (including cash
related to assets held for sale)
|
|
$
|
1,011
|
|
|
$
|
384
|
|
|
$
|
1,373
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
82
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
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 are concentrated in the following North American
onshore geographic areas:
|
|
|
|
|
the Mid-Continent area of the central and southern United
States, principally in north and east Texas, as well as 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 onshore areas of the Gulf Coast, principally in south Texas
and south Louisiana; and
|
|
|
|
the provinces of Alberta, British Columbia and Saskatchewan in
Canada.
|
Devon also has offshore operations located in the Gulf of Mexico
and certain countries outside North America, including
Azerbaijan, Brazil and China. In November 2009, Devon announced
plans to strategically reposition itself as a high-growth, North
American onshore exploration and production company. As part of
this strategic repositioning, Devon plans to bring forward the
value of its offshore assets by divesting them. In 2008 and 2007
prior to these plans, Devon sold its assets in Egypt and West
Africa. These divestiture activities are described more fully in
Note 18.
Devon also has marketing and midstream operations that perform
various activities to support the oil and gas operations of
Devon and 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;
|
83
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
obligations related to employee pension and postretirement
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, basis swaps and
costless price collars. Under the terms of the price swaps,
Devon will receive a fixed price for its production and pay a
variable market price to the contract counterparty. For the
basis swaps, Devon receives a fixed differential between two
regional gas index prices and pays a variable differential on
the same two index prices 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. Devons interest rate
swaps include contracts in which Devon receives a fixed rate and
pays a variable rate on a total notional amount. Devon also has
forward starting swaps. Under the terms of the forward starting
swaps, Devon will net settle these contracts in September 2011
or sooner should Devon elect. The net settlement amount will be
based upon Devon paying a fixed rate and receiving a floating
rate that is based upon the three-month LIBOR. The difference
between the fixed and floating rate will be applied to the
notional amount for the
30-year
period from September 30, 2011 to September 30, 2041.
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, 2009,
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
84
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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. Additionally,
Devons derivative contracts generally require cash
collateral to be posted if either its or the counterpartys
credit rating falls below investment grade. The
mark-to-market
exposure threshold, above which collateral must be posted,
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, 2009, the credit ratings of all Devons
counterparties were investment grade.
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 consolidated balance sheets and consolidated
statements of operations associated with its derivative
financial instruments.
Fair
Value Measurements
Certain of Devons assets and liabilities are measured at
fair value at each reporting date. Fair value represents the
price that would be received to sell the asset or paid to
transfer the liability in an orderly transaction between market
participants. This is price is commonly referred to as the
exit price.
Fair value measurements are classified according to a hierarchy
that prioritizes the inputs underlying the valuation techniques.
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 2 measurements are based on inputs
other than quoted prices that are generally observable for the
asset or liability. Common examples of Level 2 inputs
include quoted prices for similar assets and liabilities in
active markets or quoted prices for identical assets and
liabilities in markets not considered to be active. Level 3
measurements have the lowest priority and are based upon inputs
that are not observable from objective sources. The most common
Level 3 fair value measurement is an internally developed
cash flow model. 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.
Discontinued
Operations
As previously discussed, Devon is in the process of divesting
its offshore assets in the Gulf of Mexico and certain
International locations outside North America and previously
sold its assets in Africa in 2008 and 2007. As a result of these
divestitures and planned divestitures, all amounts related to
Devons International operations are classified as
discontinued operations. The Gulf of Mexico properties being
divested do not qualify as discontinued operations under
accounting rules. As such, amounts included in the accompanying
consolidated financial statements and these notes that pertain
to continuing operations include amounts related to Devons
offshore Gulf of Mexico operations.
The captions assets held for sale and liabilities associated
with assets held for sale in the accompanying consolidated
balance sheets present the assets and liabilities associated
with Devons discontinued operations. Devon measures its
assets held for sale at the lower of its carrying amount or
estimated fair value less costs to
85
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
sell. Additionally, Devon does not recognize depreciation,
depletion and amortization on its long-lived assets held for
sale.
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.
Future net revenues are calculated using prices that represent
the average of the
first-day-of-the-month
price for the
12-month
period prior to the end of the period. Costs included in future
net revenues are determined in a similar manner. Prior to
December 31, 2009, prices and costs used to calculate
future net revenues were those as of the end of the appropriate
quarterly period. Prices are held constant indefinitely and 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, 2009 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.
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.
86
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
Devons primary investments consist of auction rate
securities that totaled $115 million and $122 million
at December 31, 2009 and 2008, respectively. These
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.
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, 2009, issuers have redeemed $37 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 auction rate securities as long-term investments
as of December 31, 2009. These securities are included in
other long-term assets in the 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.
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 2009, 2008 and 2007. 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, 2009 and 2008.
The increase in goodwill from 2008 to 2009 is due to changes in
the exchange rate between the U.S. dollar and the Canadian
dollar.
87
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
United States
|
|
$
|
3,046
|
|
|
$
|
3,046
|
|
Canada
|
|
|
2,884
|
|
|
|
2,465
|
|
|
|
|
|
|
|
|
|
|
Total (continuing operations)
|
|
$
|
5,930
|
|
|
$
|
5,511
|
|
|
|
|
|
|
|
|
|
|
International (assets held for sale)
|
|
$
|
68
|
|
|
$
|
68
|
|
|
|
|
|
|
|
|
|
|
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, 2006
|
|
$
|
1,219
|
|
December 31, 2007
|
|
$
|
2,566
|
|
December 31, 2008
|
|
$
|
685
|
|
December 31, 2009
|
|
$
|
1,616
|
|
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.
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 in the accompanying consolidated
statements 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.
88
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 collectability 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 2009, 2008 and 2007, 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 or restructuring costs in
the accompanying statements of operations over the applicable
requisite service periods. Generally, Devon uses new shares to
grant share-based awards and to issue shares upon stock option
exercises.
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 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.
Devon recognizes the financial statement effects of tax
positions 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.
Additional information regarding Devons unrecognized tax
benefits, including changes in such amounts during 2009 and
2008, is provided in Note 17.
Pursuant to the planned divestitures of its International assets
located outside North America, Devon expects to repatriate the
earnings from the foreign subsidiaries that own the assets. As a
result, Devon has recognized U.S. deferred income taxes on
its foreign earnings as of December 31, 2009.
89
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Net
(Loss) Earnings Per Common Share
Devons basic earnings per share amounts have been computed
based on the average number of shares of common stock
outstanding for the period. Basic earnings per share includes
the effect of participating securities, which primarily consist
of Devons outstanding restricted stock awards. 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.
The components of accounts receivable include the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Oil, gas and NGL revenues
|
|
$
|
752
|
|
|
$
|
711
|
|
Joint interest billings
|
|
|
151
|
|
|
|
241
|
|
Marketing and midstream revenues
|
|
|
188
|
|
|
|
153
|
|
Production tax credits
|
|
|
110
|
|
|
|
170
|
|
Other
|
|
|
19
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
Gross accounts receivable
|
|
|
1,220
|
|
|
|
1,305
|
|
Allowance for doubtful accounts
|
|
|
(12
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
Net accounts receivable
|
|
$
|
1,208
|
|
|
$
|
1,300
|
|
|
|
|
|
|
|
|
|
|
|
|
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,
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 consolidated
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, 2009:
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps
|
|
Derivative financial instruments, current
|
|
$
|
169
|
|
|
$
|
|
|
Gas basis swaps
|
|
Derivative financial instruments, current
|
|
|
3
|
|
|
|
|
|
Oil price collars
|
|
Other current liabilities
|
|
|
|
|
|
|
38
|
|
Interest rate swaps
|
|
Derivative financial instruments, current
|
|
|
39
|
|
|
|
|
|
Interest rate swaps
|
|
Other long-term assets
|
|
|
131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
342
|
|
|
$
|
38
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
Gas price collars
|
|
Derivative financial instruments, current
|
|
$
|
255
|
|
|
$
|
|
|
Interest rate swaps
|
|
Derivative financial instruments, current
|
|
|
27
|
|
|
|
|
|
Interest rate swaps
|
|
Other long-term assets
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
359
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
(In millions)
|
|
|
Cash settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price collars
|
|
Net gain (loss) on oil and gas derivative financial instruments
|
|
$
|
450
|
|
|
$
|
(221
|
)
|
|
$
|
2
|
|
Gas price swaps
|
|
Net gain (loss) on oil and gas derivative financial instruments
|
|
|
55
|
|
|
|
(203
|
)
|
|
|
38
|
|
Oil price collars
|
|
Net gain (loss) on oil and gas derivative financial instruments
|
|
|
|
|
|
|
27
|
|
|
|
|
|
Interest rate swaps
|
|
Change in fair value of other financial instruments
|
|
|
40
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements
|
|
|
545
|
|
|
|
(396
|
)
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (losses) gains:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price collars
|
|
Net gain (loss) on oil and gas derivative financial instruments
|
|
|
(255
|
)
|
|
|
255
|
|
|
|
(4
|
)
|
Gas price swaps
|
|
Net gain (loss) on oil and gas derivative financial instruments
|
|
|
169
|
|
|
|
(12
|
)
|
|
|
(22
|
)
|
Gas basis swaps
|
|
Net gain (loss) on oil and gas derivative financial instruments
|
|
|
3
|
|
|
|
|
|
|
|
|
|
Oil price collars
|
|
Net gain (loss) on oil and gas derivative financial instruments
|
|
|
(38
|
)
|
|
|
|
|
|
|
|
|
Interest rate swaps
|
|
Change in fair value of other financial instruments
|
|
|
66
|
|
|
|
104
|
|
|
|
1
|
|
Embedded option
|
|
Change in fair value of other financial instruments
|
|
|
|
|
|
|
109
|
|
|
|
(248
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized (losses) gains
|
|
|
(55
|
)
|
|
|
456
|
|
|
|
(273
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) recognized on statement of operations
|
|
$
|
490
|
|
|
$
|
60
|
|
|
$
|
(233
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The components of other current assets include the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Inventories
|
|
$
|
182
|
|
|
$
|
142
|
|
Prepaid assets
|
|
|
33
|
|
|
|
36
|
|
Income taxes receivable
|
|
|
53
|
|
|
|
333
|
|
Other
|
|
|
2
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
Other current assets
|
|
$
|
270
|
|
|
$
|
515
|
|
|
|
|
|
|
|
|
|
|
|
|
5.
|
Property
and Equipment
|
Property and equipment consists of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Oil and gas properties:
|
|
|
|
|
|
|
|
|
Subject to amortization
|
|
$
|
52,352
|
|
|
$
|
45,678
|
|
Not subject to amortization
|
|
|
4,078
|
|
|
|
4,248
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
56,430
|
|
|
|
49,926
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(40,312
|
)
|
|
|
(30,260
|
)
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
|
16,118
|
|
|
|
19,666
|
|
|
|
|
|
|
|
|
|
|
Other property and equipment
|
|
|
4,045
|
|
|
|
3,465
|
|
Accumulated depreciation and amortization
|
|
|
(1,396
|
)
|
|
|
(1,100
|
)
|
|
|
|
|
|
|
|
|
|
Net other property and equipment
|
|
|
2,649
|
|
|
|
2,365
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net of accumulated depreciation,
depletion and amortization
|
|
$
|
18,767
|
|
|
$
|
22,031
|
|
|
|
|
|
|
|
|
|
|
In the first quarter of 2009 and the fourth quarter of 2008,
Devon reduced the carrying values of its oil and gas properties
due to full cost ceiling limitations. These reductions are
discussed in Note 15.
92
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following is a summary of Devons oil and gas
properties not subject to amortization as of December 31,
2009. The $4.1 billion total includes $2.1 billion
related to Devons U.S. Offshore assets that are
expected to be sold by the end of 2010. Evaluation of most of
the remaining $2.0 billion of 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
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2007
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Acquisition costs
|
|
$
|
129
|
|
|
$
|
1,567
|
|
|
$
|
126
|
|
|
$
|
780
|
|
|
$
|
2,602
|
|
Exploration costs
|
|
|
223
|
|
|
|
303
|
|
|
|
56
|
|
|
|
174
|
|
|
|
756
|
|
Development costs
|
|
|
326
|
|
|
|
169
|
|
|
|
34
|
|
|
|
22
|
|
|
|
551
|
|
Capitalized interest
|
|
|
74
|
|
|
|
54
|
|
|
|
37
|
|
|
|
4
|
|
|
|
169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas properties not subject to amortization
|
|
$
|
752
|
|
|
$
|
2,093
|
|
|
$
|
253
|
|
|
$
|
980
|
|
|
$
|
4,078
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.
|
Debt and
Related Expenses
|
A summary of Devons debt is as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Commercial paper
|
|
$
|
1,432
|
|
|
$
|
1,005
|
|
Other debentures and notes:
|
|
|
|
|
|
|
|
|
10.125% retired on November 15, 2009
|
|
|
|
|
|
|
177
|
|
6.875% due September 30, 2011
|
|
|
1,750
|
|
|
|
1,750
|
|
7.25% due October 1, 2011
|
|
|
350
|
|
|
|
350
|
|
5.625% due January 15, 2014
|
|
|
500
|
|
|
|
|
|
8.25% due July 1, 2018
|
|
|
125
|
|
|
|
125
|
|
6.30% due January 15, 2019
|
|
|
700
|
|
|
|
|
|
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
|
|
|
|
10
|
|
Net premium on other debentures and notes
|
|
|
12
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,279
|
|
|
|
5,841
|
|
Less amount classified as short-term debt
|
|
|
1,432
|
|
|
|
180
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
5,847
|
|
|
$
|
5,661
|
|
|
|
|
|
|
|
|
|
|
93
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Debt maturities as of December 31, 2009, excluding premiums
and discounts, are as follows (in millions):
|
|
|
|
|
2010
|
|
$
|
1,432
|
|
2011
|
|
|
2,100
|
|
2012
|
|
|
10
|
|
2013
|
|
|
|
|
2014
|
|
|
500
|
|
2015 and thereafter
|
|
|
3,225
|
|
|
|
|
|
|
Total
|
|
$
|
7,267
|
|
|
|
|
|
|
Credit
Lines
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 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, 2009, there were
no borrowings under the Senior Credit Facility.
Following the maturity of an unused $700 million short-term
facility on November 3, 2009, 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 2, 2010. 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 provides for an annual
facility fee of approximately $1.75 million that is payable
quarterly in arrears. As of December 31, 2009, 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, 2009, Devon was in compliance with this
covenant. Devons
debt-to-capitalization
ratio at December 31, 2009, as calculated pursuant to the
terms of the agreement, was 20.5%.
94
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following schedule summarizes the capacity of Devons
credit facilities by maturity date, as well as its available
capacity as of December 31, 2009 (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 2, 2010 maturity
|
|
|
700
|
|
|
|
|
|
|
Total credit facilities
|
|
|
3,350
|
|
Less:
|
|
|
|
|
Outstanding credit facility borrowings
|
|
|
|
|
Outstanding commercial paper borrowings
|
|
|
1,432
|
|
Outstanding letters of credit
|
|
|
87
|
|
|
|
|
|
|
Total available capacity
|
|
$
|
1,831
|
|
|
|
|
|
|
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,
2009, Devon had $1.4 billion of commercial paper debt
outstanding at an average rate of 0.29%. The average borrowing
rate for Devons $1.0 billion of commercial paper debt
outstanding at December 31, 2008 was 3.00%.
Other
Debentures and Notes
Following are descriptions of the various other debentures and
notes outstanding at December 31, 2009, as listed in the
table presented at the beginning of this note.
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
|
%
|
95
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
5.625% Notes
due January 15, 2014 and 6.30% Notes due
January 15, 2019
On January 9, 2009, Devon sold these notes, which are
unsecured and unsubordinated obligations of Devon. The net
proceeds from issuance of this debt were used primarily to repay
Devons outstanding commercial paper as of
December 31, 2008.
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 2007 and 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Interest based on debt outstanding
|
|
$
|
437
|
|
|
$
|
426
|
|
|
$
|
508
|
|
Capitalized interest
|
|
|
(94
|
)
|
|
|
(111
|
)
|
|
|
(102
|
)
|
Other
|
|
|
6
|
|
|
|
14
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense
|
|
$
|
349
|
|
|
$
|
329
|
|
|
$
|
430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
7.
|
Asset
Retirement Obligations
|
Following is a reconciliation of the asset retirement
obligations for the years ended December 31, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Asset retirement obligations as of beginning of year
|
|
$
|
1,387
|
|
|
$
|
1,245
|
|
Liabilities incurred
|
|
|
56
|
|
|
|
59
|
|
Liabilities settled
|
|
|
(123
|
)
|
|
|
(86
|
)
|
Revision of estimated obligation
|
|
|
33
|
|
|
|
225
|
|
Liabilities assumed by others
|
|
|
(30
|
)
|
|
|
|
|
Accretion expense on discounted obligation
|
|
|
91
|
|
|
|
80
|
|
Foreign currency translation adjustment
|
|
|
99
|
|
|
|
(136
|
)
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations as of end of year
|
|
|
1,513
|
|
|
|
1,387
|
|
Less current portion
|
|
|
95
|
|
|
|
138
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, long-term
|
|
$
|
1,418
|
|
|
$
|
1,249
|
|
|
|
|
|
|
|
|
|
|
During 2009 and 2008, Devon recognized revisions to its asset
retirement obligations totaling $33 million and
$225 million, respectively. The primary factors causing the
2009 fair value increase were an overall increase in abandonment
cost estimates, partially offset by an increase in the discount
rate used to calculate the present value of the obligations. 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.
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 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, 2009 and 2008, the fair values of the
Qualified Plans assets were $532 million and
$430 million, respectively. The assets were
$164 million less and $209 million less, 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
$39 million and $50 million at December 31, 2009
and 2008, respectively, and is included in noncurrent other
assets in the consolidated
97
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
Benefit
Obligations and Funded Status
The following table presents the status of Devons pension
and other postretirement benefit plans for 2009 and 2008. 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, 2009
and 2008 was $873 million and $795 million,
respectively. Devons benefit obligations and plan assets
are measured each year as of December 31.
98
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$
|
931
|
|
|
$
|
849
|
|
|
$
|
56
|
|
|
$
|
71
|
|
Service cost
|
|
|
43
|
|
|
|
41
|
|
|
|
1
|
|
|
|
1
|
|
Interest cost
|
|
|
58
|
|
|
|
54
|
|
|
|
3
|
|
|
|
4
|
|
Actuarial loss (gain)
|
|
|
4
|
|
|
|
17
|
|
|
|
7
|
|
|
|
(15
|
)
|
Curtailment (gain) loss
|
|
|
(26
|
)
|
|
|
|
|
|
|
1
|
|
|
|
|
|
Plan amendments
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
Foreign exchange rate changes
|
|
|
5
|
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
Participant contributions
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
2
|
|
Benefits paid
|
|
|
(35
|
)
|
|
|
(33
|
)
|
|
|
(6
|
)
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
|
980
|
|
|
|
931
|
|
|
|
64
|
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
|
430
|
|
|
|
619
|
|
|
|
|
|
|
|
|
|
Actual return on plan assets
|
|
|
80
|
|
|
|
(178
|
)
|
|
|
|
|
|
|
|
|
Employer contributions
|
|
|
55
|
|
|
|
25
|
|
|
|
4
|
|
|
|
5
|
|
Participant contributions
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
2
|
|
Benefits paid
|
|
|
(35
|
)
|
|
|
(33
|
)
|
|
|
(6
|
)
|
|
|
(7
|
)
|
Foreign exchange rate changes
|
|
|
2
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year
|
|
|
532
|
|
|
|
430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status at end of year
|
|
$
|
(448
|
)
|
|
$
|
(501
|
)
|
|
$
|
(64
|
)
|
|
$
|
(56
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts recognized in balance sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent assets
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
|
|
|
$
|
|
|
Current liabilities
|
|
|
(8
|
)
|
|
|
(10
|
)
|
|
|
(5
|
)
|
|
|
(5
|
)
|
Noncurrent liabilities
|
|
|
(442
|
)
|
|
|
(493
|
)
|
|
|
(59
|
)
|
|
|
(51
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net amount
|
|
$
|
(448
|
)
|
|
$
|
(501
|
)
|
|
$
|
(64
|
)
|
|
$
|
(56
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts recognized in accumulated other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss (gain)
|
|
$
|
334
|
|
|
$
|
440
|
|
|
$
|
(6
|
)
|
|
$
|
(13
|
)
|
Prior service cost
|
|
|
20
|
|
|
|
28
|
|
|
|
11
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
354
|
|
|
$
|
468
|
|
|
$
|
5
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 million for both 2009 and 2008, which were
transferred from the trusts established for the Supplemental
Plans.
99
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Certain of Devons pension plans have a projected benefit
obligation and accumulated benefit obligation in excess of plan
assets at December 31, 2009 and 2008 as presented in the
table below.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Projected benefit obligation
|
|
$
|
967
|
|
|
$
|
921
|
|
Accumulated benefit obligation
|
|
$
|
860
|
|
|
$
|
784
|
|
Fair value of plan assets
|
|
$
|
517
|
|
|
$
|
417
|
|
The plan assets included in the above table exclude the
Supplemental Plan trusts, which had a total value of
$39 million and $50 million at December 31, 2009
and 2008, 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 2009, 2008
and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
Pension Benefits
|
|
|
Postretirement Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
43
|
|
|
$
|
41
|
|
|
$
|
30
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
Interest cost
|
|
|
58
|
|
|
|
54
|
|
|
|
46
|
|
|
|
3
|
|
|
|
4
|
|
|
|
3
|
|
Expected return on plan assets
|
|
|
(35
|
)
|
|
|
(50
|
)
|
|
|
(49
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Curtailment and settlement expense
|
|
|
5
|
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
Plan amendment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Recognition of net actuarial loss (gain)
|
|
|
45
|
|
|
|
14
|
|
|
|
12
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
1
|
|
Recognition of prior service cost
|
|
|
3
|
|
|
|
2
|
|
|
|
1
|
|
|
|
2
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net periodic benefit cost
|
|
|
119
|
|
|
|
61
|
|
|
|
41
|
|
|
|
6
|
|
|
|
7
|
|
|
|
6
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial (gain) loss arising in current year
|
|
|
(66
|
)
|
|
|
245
|
|
|
|
54
|
|
|
|
7
|
|
|
|
(15
|
)
|
|
|
(3
|
)
|
Prior service cost arising in current year
|
|
|
|
|
|
|
9
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
22
|
|
Recognition of net actuarial (loss) gain in net periodic benefit
cost
|
|
|
(45
|
)
|
|
|
(14
|
)
|
|
|
(12
|
)
|
|
|
1
|
|
|
|
|
|
|
|
(1
|
)
|
Recognition of prior service cost, including curtailment, in net
periodic benefit cost
|
|
|
(8
|
)
|
|
|
(2
|
)
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
|
|
Curtailment of pension benefits
|
|
|
|
|
|
|
|
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in additional minimum pension liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income (loss)
|
|
|
(119
|
)
|
|
|
238
|
|
|
|
42
|
|
|
|
6
|
|
|
|
(17
|
)
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized
|
|
$
|
|
|
|
$
|
299
|
|
|
$
|
83
|
|
|
$
|
12
|
|
|
$
|
(10
|
)
|
|
$
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
Benefits
|
|
|
|
(In millions)
|
|
|
Net actuarial loss
|
|
$
|
27
|
|
|
$
|
|
|
Prior service cost
|
|
|
3
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
30
|
|
|
$
|
1
|
|
|
|
|
|
|
|
|
|
|
Assumptions
The following table presents the weighted average actuarial
assumptions that were used to determine benefit obligations and
net periodic benefit costs for 2009, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
Pension Benefits
|
|
|
Postretirement Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Assumptions to determine benefit obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
6.00
|
%
|
|
|
6.00
|
%
|
|
|
6.22
|
%
|
|
|
5.70
|
%
|
|
|
6.00
|
%
|
|
|
6.00
|
%
|
Rate of compensation increase
|
|
|
6.95
|
%
|
|
|
7.00
|
%
|
|
|
7.00
|
%
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Assumptions to determine net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
6.00
|
%
|
|
|
6.18
|
%
|
|
|
5.96
|
%
|
|
|
6.00
|
%
|
|
|
6.00
|
%
|
|
|
5.75
|
%
|
Expected return on plan assets
|
|
|
7.18
|
%
|
|
|
8.40
|
%
|
|
|
8.40
|
%
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Rate of compensation increase
|
|
|
6.95
|
%
|
|
|
7.00
|
%
|
|
|
7.00
|
%
|
|
|
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 2009 benefit obligation for the pension plans, the 6.95%
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.
Expected return on plan assets 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. See
plan assets discussion below for more information on
Devons target allocations.
Other assumptions For measurement of the 2009
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 2010. The rate was
assumed to decrease annually to an ultimate rate of 5% in the
year 2029 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
101
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
effects on the December 31, 2009 other postretirement
benefits obligation and the 2010 service and interest cost
components of net periodic benefit cost.
|
|
|
|
|
|
|
|
|
|
|
One
|
|
|
One
|
|
|
|
Percent
|
|
|
Percent
|
|
|
|
Increase
|
|
|
Decrease
|
|
|
|
(In millions)
|
|
|
Effect on benefit obligation
|
|
$
|
5
|
|
|
$
|
(4
|
)
|
Effect on service and interest costs
|
|
$
|
|
|
|
$
|
|
|
Pension
Plan Assets
Devons overall investment objective for its pension
plans assets is to achieve long-term growth of invested
capital and income to ensure benefit payments 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.
The vast majority of Devons plan assets are invested in
diversified asset types to generate long-term growth and income.
The remaining plan assets, generally less than 5%, are invested
in assets that can be used for near-term benefit payments.
Derivatives or other speculative investments considered high
risk are generally prohibited.
At the end of 2009, Devons target allocations for plan
assets are 47.5% for equity securities, 40% for fixed-income
securities and 12.5% for other investment types. At the end of
2008, Devons target allocation was 60% for equity
securities and 40% for fixed income securities. The fair values
of Devons pension assets at December 31, 2009 and
2008, are presented by asset class in the following tables.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
Actual
|
|
|
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
Allocation
|
|
|
Total
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
|
(In millions)
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States large cap
|
|
|
18.8
|
%
|
|
$
|
100
|
|
|
$
|
|
|
|
$
|
100
|
|
|
$
|
|
|
United States small cap
|
|
|
15.2
|
%
|
|
|
81
|
|
|
|
81
|
|
|
|
|
|
|
|
|
|
International large cap
|
|
|
15.2
|
%
|
|
|
81
|
|
|
|
44
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity securities
|
|
|
49.2
|
%
|
|
|
262
|
|
|
|
125
|
|
|
|
137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-income securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate bonds
|
|
|
25.1
|
%
|
|
|
133
|
|
|
|
133
|
|
|
|
|
|
|
|
|
|
United States Treasury obligations
|
|
|
9.8
|
%
|
|
|
52
|
|
|
|
52
|
|
|
|
|
|
|
|
|
|
Other bonds
|
|
|
3.9
|
%
|
|
|
21
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fixed-income securities
|
|
|
38.8
|
%
|
|
|
206
|
|
|
|
206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investment funds
|
|
|
2.4
|
%
|
|
|
13
|
|
|
|
|
|
|
|
13
|
|
|
|
|
|
Hedge funds
|
|
|
9.6
|
%
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other securities
|
|
|
12.0
|
%
|
|
|
64
|
|
|
|
|
|
|
|
13
|
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total investments
|
|
|
100.0
|
%
|
|
$
|
532
|
|
|
$
|
331
|
|
|
$
|
150
|
|
|
$
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
102
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
Actual
|
|
|
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
Allocation
|
|
|
Total
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
|
(In millions)
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States large cap
|
|
|
25.8
|
%
|
|
$
|
111
|
|
|
$
|
|
|
|
$
|
111
|
|
|
$
|
|
|
United States small cap
|
|
|
14.9
|
%
|
|
|
64
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
International large cap
|
|
|
14.0
|
%
|
|
|
60
|
|
|
|
34
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity securities
|
|
|
54.7
|
%
|
|
|
235
|
|
|
|
98
|
|
|
|
137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-income securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate bonds
|
|
|
29.1
|
%
|
|
|
125
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
United States Treasury obligations
|
|
|
8.8
|
%
|
|
|
38
|
|
|
|
38
|
|
|
|
|
|
|
|
|
|
Other bonds
|
|
|
3.0
|
%
|
|
|
13
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fixed-income securities
|
|
|
40.9
|
%
|
|
|
176
|
|
|
|
176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other securities Short-term investment funds
|
|
|
4.4
|
%
|
|
|
19
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total investments
|
|
|
100.0
|
%
|
|
$
|
430
|
|
|
$
|
274
|
|
|
$
|
156
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following methods and assumptions were used to estimate the
fair values of the assets and liabilities in the tables above.
Equity securities Devons equity
securities consist of investments in United States large and
small capitalization companies and international large
capitalization companies. These equity securities are actively
traded securities that can be redeemed upon demand. The fair
values of these Level 1 securities are based upon quoted
market prices.
Devons equity securities also include commingled funds
that invest in large capitalization companies. These equity
securities can be redeemed on demand but are not actively
traded. The fair values of these Level 2 securities are
based upon the net asset values provided by the investment
managers.
Fixed-income securities Devons
fixed-income securities consist of bonds issued by
investment-grade companies from diverse industries, United
States Treasury obligations and asset-backed securities.
Devons fixed-income securities are actively traded
securities that can be redeemed upon demand. The fair values of
these Level 1 securities are based upon quoted market
prices.
Other securities Devons other
securities include commingled, short-term investment funds.
These securities can be redeemed on demand but are not actively
traded. The fair values of these Level 2 securities are
based upon the net asset values provided by investment managers.
Devons other securities also include a hedge fund of funds
that invests both long and short using a variety of investment
strategies. Management of the hedge fund has the ability to
shift investments from value to growth strategies, from small to
large capitalization stocks, and from a net long position to a
net short position. Devons hedge fund is not actively
traded and Devon is subject to redemption restrictions with
regards to this investment. The fair value of this Level 3
investment represents the fair value as determined by the hedge
fund manager.
103
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The change in Devons Level 3 plan assets between 2008
and 2009 related entirely to purchases made in 2009.
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 2010 contributions
|
|
$
|
34
|
|
|
$
|
5
|
|
Benefit payments:
|
|
|
|
|
|
|
|
|
2010
|
|
$
|
39
|
|
|
$
|
5
|
|
2011
|
|
$
|
41
|
|
|
$
|
5
|
|
2012
|
|
$
|
45
|
|
|
$
|
6
|
|
2013
|
|
$
|
49
|
|
|
$
|
6
|
|
2014
|
|
$
|
53
|
|
|
$
|
6
|
|
2015 to 2019
|
|
$
|
338
|
|
|
$
|
29
|
|
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 2010, $7 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.
Other
Benefit Plans
Devons 401(k) Plan covers all its employees in the United
States. 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.
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.
104
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents Devons expense related to
these defined contribution plans during 2009, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
401(k) plan
|
|
$
|
20
|
|
|
$
|
21
|
|
|
$
|
18
|
|
Enhanced contribution plan
|
|
|
14
|
|
|
|
12
|
|
|
|
|
|
Canadian pension and savings plans
|
|
|
15
|
|
|
|
16
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expense
|
|
$
|
49
|
|
|
$
|
49
|
|
|
$
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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). At December 31, 2009, 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.
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 previously 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 was created as a potential use of the proceeds received
from Devons West African property divestitures. Both of
these plans expired on December 31, 2009, and no new plans
have been authorized. Devons Board of Directors also
approved a separate 50 million share repurchase program in
August 2005, which expired on December 31, 2007.
During 2007 and 2008, Devon repurchased 10.6 million shares
at a total cost of $1.0 billion, or an average of $93.76
per share, under its repurchase programs. No shares were
repurchased in 2009. The
105
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
following table summarizes Devons repurchases under
approved plans during 2008 and 2007 (amounts and shares in
millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
Repurchase Program
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
$
|
665
|
|
|
|
6.5
|
|
|
$
|
102.56
|
|
|
$
|
326
|
|
|
|
4.1
|
|
|
$
|
79.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
Devon paid common stock dividends of $284 million (or $0.64
per share), $284 million (or $0.64 per share) and
$249 million (or $0.56 per share) in 2009, 2008 and 2007
respectively. Devon paid dividends of $5 million in 2008
and $10 million in 2007 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 and similar state statutes. In
response to liabilities associated with these activities, loss
accruals primarily consist of estimated uninsured costs
associated with remediation. Devons monetary exposure for
environmental matters 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. Devon does not
currently believe that it is subject to material exposure with
respect to such royalty matters.
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.
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 was later appealed to the United States Supreme Court,
which, in
106
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
October 2009, declined to review the appellate courts
ruling. The Supreme Courts decision ended the MMSs
judicial course to enforce the price thresholds.
Prior to September 30, 2009, Devon had $84 million
accrued for potential royalties on various deep water leases.
Based upon the Supreme Courts decision, Devon reduced to
zero the $84 million loss contingency accrual in the third
quarter of 2009. The $84 million expense reduction is
included in other income in the accompanying 2009 consolidated
statement of operations.
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. Devon
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 consolidated
statement of operations for 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 in
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 in the Gulf
of Mexico.
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 have been repaired and
restored and production operations that will not be restored.
These damages are uninsured losses because they resulted from
named windstorms in the Gulf of Mexico.
For the damaged facilities and transportation systems which have
been repaired or restored, Devon recognized a loss of
$31 million in 2008. This loss is included in lease
operating expenses in the accompanying consolidated statement of
operations. The facilities for which Devon did not restore
production operations consisted of certain platforms that were
completely destroyed. Devon began performing asset retirement
activities associated with the destroyed platforms and related
wells in 2008. 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 were
$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 consolidated balance sheet.
Other
Matters
Devon is involved in other various routine legal proceedings
incidental to its business. However, to Devons knowledge,
there were no other material pending legal proceedings to which
Devon is a party or to which any of its property is subject.
107
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 $3.2 billion total of
Drilling and Facility Obligations in the table below
is $1.4 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 $1.4 billion
represents the gross commitment under these contracts.
Devons ultimate payment for these commitments will be
reduced by any amounts billed to its partners until Devon sells
the associated offshore properties. Payments for these
commitments, net of amounts billed to partners, will be
capitalized as a component of oil and gas properties.
Additionally, Devons commitment under these contracts may
be further reduced if the buyers of its offshore assets assume
all or a portion of the obligations. If the buyers do not assume
these obligations, Devon will attempt to sublease the rigs to
reduce its commitment. However, if the buyers do not assume the
obligations and Devon is not able to sublease the rigs, Devon
would be contractually committed to the amounts related to the
remaining lease periods.
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 $56 million, $44 million and
$42 million in 2009, 2008 and 2007, 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 2009, 2008 and 2007. Devon has
guaranteed that the Nansen spar will have a residual value at
the end of the 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 2018. Devon is
also leasing an FPSO that is being used in the Polvo project
offshore Brazil. This lease expires in 2014. Devon has also
leased an FPSO that will be used when production from its
Cascade development in the Gulf of Mexico begins in 2010. This
lease expires in 2015. Total rental expense included in lease
operating expenses for these FPSOs was $36 million,
$25 million and $17 million in 2009, 2008 and 2007,
respectively. Devon expects the eventual buyers of these
offshore assets will assume the FPSO leases. However, the
amounts in the schedule below reflect its full commitments under
the leases.
108
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2009. The schedule includes separate amounts
for Devons continuing and discontinued operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
|
|
|
Firm
|
|
|
Office and
|
|
|
|
|
|
|
|
|
|
Facility
|
|
|
Transportation
|
|
|
Equipment
|
|
|
Spar
|
|
|
FPSO
|
|
Year Ending December 31,
|
|
Obligations
|
|
|
Agreements
|
|
|
Leases
|
|
|
Leases
|
|
|
Leases
|
|
|
|
(In millions)
|
|
|
Continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
$
|
992
|
|
|
$
|
298
|
|
|
$
|
57
|
|
|
$
|
11
|
|
|
$
|
58
|
|
2011
|
|
|
516
|
|
|
|
267
|
|
|
|
54
|
|
|
|
11
|
|
|
|
37
|
|
2012
|
|
|
302
|
|
|
|
241
|
|
|
|
40
|
|
|
|
22
|
|
|
|
38
|
|
2013
|
|
|
257
|
|
|
|
217
|
|
|
|
34
|
|
|
|
13
|
|
|
|
38
|
|
2014
|
|
|
97
|
|
|
|
202
|
|
|
|
15
|
|
|
|
27
|
|
|
|
38
|
|
Thereafter
|
|
|
1
|
|
|
|
714
|
|
|
|
147
|
|
|
|
78
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,165
|
|
|
|
1,939
|
|
|
|
347
|
|
|
|
162
|
|
|
|
225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
622
|
|
|
|
|
|
|
|
15
|
|
|
|
|
|
|
|
37
|
|
2011
|
|
|
182
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
|
|
2012
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
|
|
2013
|
|
|
110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,084
|
|
|
|
|
|
|
|
15
|
|
|
|
|
|
|
|
200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operations
|
|
$
|
3,249
|
|
|
$
|
1,939
|
|
|
$
|
362
|
|
|
$
|
162
|
|
|
$
|
425
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2009 and 2008.
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, 2009
and 2008. These assets and liabilities are not presented in the
following tables.
Information regarding the fair values of Devons pension
plan assets is provided in Note 8.
109
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
Carrying
|
|
|
Total
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
Amount
|
|
|
Fair Value
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
|
(In millions)
|
|
|
Financial assets (liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps
|
|
$
|
169
|
|
|
$
|
169
|
|
|
$
|
|
|
|
$
|
169
|
|
|
$
|
|
|
Gas basis swaps
|
|
$
|
3
|
|
|
$
|
3
|
|
|
$
|
|
|
|
$
|
3
|
|
|
$
|
|
|
Oil price collars
|
|
$
|
(38
|
)
|
|
$
|
(38
|
)
|
|
$
|
|
|
|
$
|
(38
|
)
|
|
$
|
|
|
Interest rate swaps
|
|
$
|
170
|
|
|
$
|
170
|
|
|
$
|
|
|
|
$
|
170
|
|
|
$
|
|
|
Debt
|
|
$
|
(7,279
|
)
|
|
$
|
(8,214
|
)
|
|
$
|
(1,432
|
)
|
|
$
|
(6,782
|
)
|
|
$
|
|
|
Long-term investments
|
|
$
|
115
|
|
|
$
|
115
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
115
|
|
Asset retirement obligations(1)
|
|
$
|
(1,622
|
)
|
|
$
|
(1,622
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(1,622
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
Carrying
|
|
|
Total
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
Amount
|
|
|
Fair Value
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
|
(In millions)
|
|
|
Financial assets (liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price collars
|
|
$
|
255
|
|
|
$
|
255
|
|
|
$
|
|
|
|
$
|
255
|
|
|
$
|
|
|
Interest rate swaps
|
|
$
|
104
|
|
|
$
|
104
|
|
|
$
|
|
|
|
$
|
104
|
|
|
$
|
|
|
Debt
|
|
$
|
(5,841
|
)
|
|
$
|
(6,106
|
)
|
|
$
|
(1,005
|
)
|
|
$
|
(5,101
|
)
|
|
$
|
|
|
Long-term investments
|
|
$
|
122
|
|
|
$
|
122
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
122
|
|
Asset retirement obligations(1)
|
|
$
|
(1,485
|
)
|
|
$
|
(1,485
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(1,485
|
)
|
|
|
|
(1) |
|
Includes $109 million and $98 million of asset
retirement obligations related to Devons discontinued
operations at December 31, 2009 and 2008, respectively. |
The following methods and assumptions were used to estimate the
fair values of the assets and liabilities in the tables above.
Level 1
Fair Value Measurements
Debt The fair value of Devons
variable-rate commercial paper borrowings is the carrying value.
Level 2
Fair Value Measurements
Oil and gas price swaps, basis swaps and
collars The fair values of the oil and gas price
collars, gas swaps and gas basis swaps 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. The most significant input to
the cash flow calculations is Devons estimate of future
commodity prices. Devon bases its 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 the cash flow calculations is Devons estimate
of volatility for these forward curves, which is based primarily
upon implied
110
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
volatility. The resulting estimated future cash inflows or
outflows over the lives of the contracts are discounted
primarily using LIBOR and money market futures rates. These
pricing and discounting inputs are sensitive to the period of
the contract, as well as changes in forward prices and regional
price differentials.
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. The
most significant input to Devons cash flow calculations is
its estimate of future interest rate yields. Devon bases its
estimate of future yields upon its own internal model that
utilizes forward curves such as the LIBOR or the Federal Funds
Rate provided by third parties. The resulting estimated future
cash inflows or outflows over the lives of the contracts are
discounted primarily using LIBOR and money market futures rates.
These yield and discounting inputs are sensitive to the period
of the contract, as well as changes in forward interest rate
yields.
Debt 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.
Level 3
Fair Value Measurements
Long-term investments Devons long-term
investments presented in the tables above consisted entirely of
auction rate securities. 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, 2009 and
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. 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. 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, 2009 and December 31, 2008. At this time,
Devon does not believe the values of its long-term securities
are impaired. The changes in these Level 3 assets during
2008 and 2009 consisted entirely of redemptions of principal.
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
2009 and 2008, are presented in Note 7.
|
|
12.
|
Share-Based
Compensation
|
On June 3, 2009, Devons stockholders adopted the 2009
Long-Term Incentive Plan, which expires on June 2, 2019.
This plan 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 restricted stock units, performance units,
stock appreciation rights and cash-out rights to eligible
employees. The plan also authorizes the grant of nonqualified
stock options, restricted stock awards, restricted stock units
and stock appreciation rights to directors. A total of
21.5 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 1.84 shares.
Devon also has stock option plans that were adopted in 2005,
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
111
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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. and Santa Fe Snyder.
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, 2009, 2008 and
2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Gross general and administrative expense
|
|
$
|
209
|
|
|
$
|
212
|
|
|
$
|
146
|
|
Share-based compensation expense capitalized pursuant to the
full cost method of accounting for oil and gas properties
|
|
$
|
66
|
|
|
$
|
54
|
|
|
$
|
44
|
|
Related income tax benefit
|
|
$
|
43
|
|
|
$
|
47
|
|
|
$
|
28
|
|
Stock
Options
Under Devons 2009 Long-Term Incentive Plan, the exercise
price of stock options granted may not be less than the 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 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.
112
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2009, 2008 and 2007. All such
amounts represent the weighted-average amounts for each year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Grant-date fair value
|
|
$
|
22.85
|
|
|
$
|
21.77
|
|
|
$
|
26.43
|
|
Volatility factor
|
|
|
47.7
|
%
|
|
|
44.3
|
%
|
|
|
31.6
|
%
|
Dividend yield
|
|
|
0.9
|
%
|
|
|
0.9
|
%
|
|
|
0.7
|
%
|
Risk-free interest rate
|
|
|
2.1
|
%
|
|
|
1.2
|
%
|
|
|
5.0
|
%
|
Expected term (in years)
|
|
|
4.0
|
|
|
|
3.8
|
|
|
|
4.0
|
|
The following table presents a summary of Devons
outstanding stock options as of December 31, 2009,
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, 2008
|
|
|
11,894
|
|
|
$
|
55.16
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
2,026
|
|
|
$
|
63.13
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(1,497
|
)
|
|
$
|
31.27
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(263
|
)
|
|
$
|
71.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009
|
|
|
12,160
|
|
|
$
|
59.07
|
|
|
|
3.6
|
|
|
$
|
205
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested and expected to vest at December 31, 2009
|
|
|
12,128
|
|
|
$
|
59.05
|
|
|
|
3.6
|
|
|
$
|
204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2009
|
|
|
8,371
|
|
|
$
|
54.74
|
|
|
|
2.8
|
|
|
$
|
176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic value of stock options that were
exercised during 2009, 2008 and 2007 was $51 million,
$263 million and $151 million, respectively. As of
December 31, 2009, Devons unrecognized compensation
cost related to unvested stock options was $66 million.
Such cost is expected to be recognized over a weighted-average
period of 2.6 years.
Restricted
Stock Awards and Units
Under Devons 2009 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, 2009, including
changes during the year then ended.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Restricted
|
|
|
Average
|
|
|
|
Stock
|
|
|
Grant-Date
|
|
|
|
Awards
|
|
|
Fair Value
|
|
|
|
(In thousands)
|
|
|
|
|
|
Unvested at December 31, 2008
|
|
|
6,334
|
|
|
$
|
72.66
|
|
Granted
|
|
|
2,656
|
|
|
$
|
63.59
|
|
Vested
|
|
|
(2,679
|
)
|
|
$
|
70.16
|
|
Forfeited
|
|
|
(146
|
)
|
|
$
|
73.59
|
|
|
|
|
|
|
|
|
|
|
Unvested at December 31, 2009
|
|
|
6,165
|
|
|
$
|
69.76
|
|
|
|
|
|
|
|
|
|
|
The aggregate fair value of restricted stock awards that vested
during 2009, 2008 and 2007 was $165 million,
$185 million and $136 million, respectively. As of
December 31, 2009, Devons unrecognized compensation
cost related to unvested restricted stock awards and units was
$316 million. Such cost is expected to be recognized over a
weighted-average period of 2.2 years.
In the fourth quarter of 2009, Devon recognized
$153 million of estimated employee severance costs
associated with the planned divestitures of its offshore assets
that was announced in November 2009. This amount was based on
estimates of the number of employees that will ultimately be
impacted by the divestitures, and includes $63 million
related to accelerated vesting of share-based grants. Of the
$153 million total, $105 million relates to
Devons U.S. Offshore operations and the remainder
relates to its International discontinued operations.
As of the date these financial statements were prepared, only
one of the properties Devon intends to sell had actually been
sold. Furthermore, the vast majority of employees will not be
impacted by the divestitures until the properties are sold.
Therefore, Devons estimate of employee severance costs
recognized in the fourth quarter of 2009 was based upon certain
key estimates that could change as properties are sold. These
estimates include the number of impacted employees, the number
of employees offered comparable positions with the buyers and
the date of separation for impacted employees.
|
|
14.
|
Other
Financial Instruments
|
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 shares of Chevron common stock and the exchange option
embedded in the debt were always 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
114
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
accumulated other comprehensive income. Effective
January 1, 2007, under new accounting rules, Devon elected
to begin recognizing the change in fair value of the Chevron
common stock in its results of operations. 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, were both
included in Devons results of operations. Also, as a
result of this change, Devon reclassified $364 million of
after-tax unrealized gains related to Devons investment in
Chevron common stock from accumulated other comprehensive income
to retained earnings in the first quarter of 2007.
The following table presents the changes in fair value and cash
settlements related to Devons other financial instruments,
as well as its investment in Chevron Common Stock as presented
in the accompanying consolidated statements of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
(Gains) and losses from:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps fair value changes (See
Note 3)
|
|
$
|
(66
|
)
|
|
$
|
(104
|
)
|
|
$
|
(1
|
)
|
Interest rate swaps settlements (See Note 3)
|
|
|
(40
|
)
|
|
|
(1
|
)
|
|
|
|
|
Chevron common stock
|
|
|
|
|
|
|
363
|
|
|
|
(281
|
)
|
Option embedded in exchangeable debentures
|
|
|
|
|
|
|
(109
|
)
|
|
|
248
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(106
|
)
|
|
$
|
149
|
|
|
$
|
(34
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15.
|
Reduction
of Carrying Value of Oil and Gas Properties
|
During 2009 and 2008, Devon reduced the carrying values of
certain of its oil and gas properties due to full cost ceiling
limitations. A summary of these reductions and additional
discussion is provided below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
Net of
|
|
|
|
|
|
Net of
|
|
|
|
Gross
|
|
|
Taxes
|
|
|
Gross
|
|
|
Taxes
|
|
|
|
(In millions)
|
|
|
United States
|
|
$
|
6,408
|
|
|
$
|
4,085
|
|
|
$
|
6,538
|
|
|
$
|
4,168
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
3,353
|
|
|
|
2,488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,408
|
|
|
$
|
4,085
|
|
|
$
|
9,891
|
|
|
$
|
6,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The 2009 reduction was recognized in the first quarter and the
2008 reductions were recognized in the fourth quarter. The
reductions resulted from significant decreases in each
countrys full cost ceiling compared to the immediately
preceding quarter. The lower United States ceiling value in the
first quarter of 2009 largely resulted from the effects of
declining natural gas prices subsequent to December 31,
2008. The lower ceiling values in the fourth quarter of 2008
largely resulted from the effects of sharp declines in oil, gas
and NGL prices compared to September 30, 2008.
115
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The components of other income include the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Interest and dividend income
|
|
$
|
8
|
|
|
$
|
54
|
|
|
$
|
48
|
|
Reduction of deep water royalties (see Note 10)
|
|
|
84
|
|
|
|
|
|
|
|
|
|
Hurricane insurance proceeds (see Note 10)
|
|
|
|
|
|
|
162
|
|
|
|
|
|
Other
|
|
|
(24
|
)
|
|
|
1
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
68
|
|
|
$
|
217
|
|
|
$
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax (Benefit) Expense
The (loss) earnings from continuing operations before income
taxes and the components of income tax (benefit) expense for the
years 2009, 2008 and 2007 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
(Loss) earnings from continuing operations before income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
(4,961
|
)
|
|
$
|
(2,190
|
)
|
|
$
|
2,642
|
|
Canada
|
|
|
435
|
|
|
|
(1,970
|
)
|
|
|
685
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(4,526
|
)
|
|
$
|
(4,160
|
)
|
|
$
|
3,327
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income tax expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
$
|
45
|
|
|
$
|
258
|
|
|
$
|
83
|
|
Various states
|
|
|
18
|
|
|
|
31
|
|
|
|
17
|
|
Canada and various provinces
|
|
|
178
|
|
|
|
152
|
|
|
|
135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current tax expense
|
|
|
241
|
|
|
|
441
|
|
|
|
235
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax (benefit) expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
|
(1,846
|
)
|
|
|
(875
|
)
|
|
|
745
|
|
Various states
|
|
|
(111
|
)
|
|
|
(65
|
)
|
|
|
28
|
|
Canada and various provinces
|
|
|
(57
|
)
|
|
|
(622
|
)
|
|
|
(166
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax (benefit) expense
|
|
|
(2,014
|
)
|
|
|
(1,562
|
)
|
|
|
607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax (benefit) expense
|
|
$
|
(1,773
|
)
|
|
$
|
(1,121
|
)
|
|
$
|
842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The taxes on the results of discontinued operations presented in
the accompanying consolidated statements of operations were all
related to Devons international operations outside North
America.
116
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Total income tax (benefit) expense differed from the amounts
computed by applying the U.S. federal income tax rate to
(loss) earnings from continuing operations before income taxes
as a result of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Expected income tax (benefit) expense based on U.S. statutory
tax rate of 35%
|
|
$
|
(1,584
|
)
|
|
$
|
(1,456
|
)
|
|
$
|
1,164
|
|
State income taxes
|
|
|
(99
|
)
|
|
|
(29
|
)
|
|
|
30
|
|
Taxation on Canadian operations
|
|
|
(31
|
)
|
|
|
227
|
|
|
|
(10
|
)
|
Repatriations and tax policy election changes
|
|
|
|
|
|
|
312
|
|
|
|
|
|
Canadian statutory rate reduction
|
|
|
|
|
|
|
|
|
|
|
(261
|
)
|
Other
|
|
|
(59
|
)
|
|
|
(175
|
)
|
|
|
(81
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax (benefit) expense
|
|
$
|
(1,773
|
)
|
|
$
|
(1,121
|
)
|
|
$
|
842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During 2008, Devon repatriated $2.6 billion from certain
foreign subsidiaries to the United States. 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 $312 million during
2008. Of the $312 million, $295 million was recognized
as current income tax expense, and $17 million was
recognized as deferred tax expense.
In 2007, deferred income taxes were reduced $261 million
due to a Canadian statutory rate reduction that was enacted in
that year.
Deferred
Tax Assets and Liabilities
The tax effects of temporary differences that gave rise to
significant portions of the deferred tax assets and liabilities
at December 31, 2009 and 2008 are presented below:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
11
|
|
|
$
|
13
|
|
Asset retirement obligations
|
|
|
474
|
|
|
|
442
|
|
Pension benefit obligations
|
|
|
130
|
|
|
|
172
|
|
Other
|
|
|
133
|
|
|
|
74
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
748
|
|
|
|
701
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
(2,315
|
)
|
|
|
(4,163
|
)
|
Fair value of financial instruments
|
|
|
(108
|
)
|
|
|
(132
|
)
|
Long-term debt
|
|
|
(162
|
)
|
|
|
(69
|
)
|
Other
|
|
|
(62
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(2,647
|
)
|
|
|
(4,364
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(1,899
|
)
|
|
$
|
(3,663
|
)
|
|
|
|
|
|
|
|
|
|
117
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As shown in the above table, Devon has recognized
$748 million of deferred tax assets as of December 31,
2009. Included in total deferred tax assets is $11 million
related to various carryforwards available to offset future
income taxes. The carryforwards consist of $151 million of
state net operating loss carryforwards, which expire primarily
between 2010 and 2029. The tax benefits of carryforwards are
recorded as an asset to the extent that management assesses the
utilization of such carryforwards to be more likely than
not. When the future utilization of some portion of the
carryforwards is determined not to be more likely than
not, a valuation allowance is provided to reduce the
recorded tax benefits from such assets.
Devon expects the tax benefits from the net operating loss
carryforwards to be utilized between 2010 and 2014. 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
tax carryforwards prior to their expiration.
Unrecognized
Tax Benefits
The following table presents changes in Devons
unrecognized tax benefits for the year ended December 31,
2009 (in millions).
|
|
|
|
|
Balance as of December 31, 2008
|
|
$
|
260
|
|
Increases (decreases) due to:
|
|
|
|
|
Tax positions taken in current year
|
|
|
20
|
|
Accrual of interest related to tax positions taken
|
|
|
7
|
|
Lapse of statute of limitations
|
|
|
(15
|
)
|
Settlements
|
|
|
(5
|
)
|
Foreign currency translation
|
|
|
5
|
|
|
|
|
|
|
Balance as of December 31, 2009
|
|
$
|
272
|
|
|
|
|
|
|
Devons unrecognized tax benefit balance at
December 31, 2009 and 2008 included $35 million and
$29 million of interest and penalties, respectively. If
recognized, all of Devons unrecognized tax benefits as of
December 31, 2009 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
|
|
|
2005-2009
|
|
Various U.S. states
|
|
|
2005-2009
|
|
Canada federal
|
|
|
2001-2009
|
|
Various Canadian provinces
|
|
|
2001-2009
|
|
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.
118
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
18.
|
Discontinued
Operations
|
For the three-year period ended December 31, 2009,
Devons discontinued operations include amounts related to
its assets in Azerbaijan, Brazil, China and other minor
International properties that it is in the process of divesting.
Additionally, during 2007 and 2008, Devons discontinued
operations included amounts related to its assets in Egypt and
West Africa, including Equatorial Guinea, Cote dIvoire,
Gabon and other countries in the region, until they were sold.
Devons African sales generated total proceeds of
$3.0 billion. The following table presents the gains on the
African divestiture transactions by year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
Net of
|
|
|
|
|
|
Net of
|
|
|
|
|
|
Net of
|
|
|
|
Gross
|
|
|
Taxes
|
|
|
Gross
|
|
|
Taxes
|
|
|
Gross
|
|
|
Taxes
|
|
|
|
(In millions)
|
|
|
Egypt
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
90
|
|
|
$
|
90
|
|
Equatorial Guinea
|
|
|
|
|
|
|
|
|
|
|
619
|
|
|
|
544
|
|
|
|
|
|
|
|
|
|
Gabon
|
|
|
|
|
|
|
|
|
|
|
117
|
|
|
|
122
|
|
|
|
|
|
|
|
|
|
Cote dIvoire
|
|
|
17
|
|
|
|
17
|
|
|
|
83
|
|
|
|
95
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
17
|
|
|
$
|
17
|
|
|
$
|
819
|
|
|
$
|
769
|
|
|
$
|
90
|
|
|
$
|
90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues related to Devons discontinued operations totaled
$945 million, $1.7 billion and $2.2 billion
during 2009, 2008 and 2007, respectively. Earnings from
discontinued operations before income taxes totaled
$322 million, $1.3 billion and $1.6 billion
during 2009, 2008 and 2007, respectively.
119
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents the main classes of assets and
liabilities associated with Devons discontinued operations
as of December 31, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
365
|
|
|
$
|
189
|
|
Accounts receivable
|
|
|
165
|
|
|
|
112
|
|
Other current assets
|
|
|
127
|
|
|
|
91
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
657
|
|
|
$
|
392
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net of accumulated depreciation,
depletion and amortization
|
|
$
|
1,099
|
|
|
$
|
954
|
|
Goodwill
|
|
|
68
|
|
|
|
68
|
|
Other long-term assets
|
|
|
83
|
|
|
|
106
|
|
|
|
|
|
|
|
|
|
|
Total long-term assets
|
|
$
|
1,250
|
|
|
$
|
1,128
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
158
|
|
|
$
|
220
|
|
Other current liabilities
|
|
|
76
|
|
|
|
145
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
234
|
|
|
$
|
365
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, long-term
|
|
$
|
109
|
|
|
$
|
98
|
|
Deferred income taxes
|
|
|
101
|
|
|
|
65
|
|
Other liabilities
|
|
|
3
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities
|
|
$
|
213
|
|
|
$
|
166
|
|
|
|
|
|
|
|
|
|
|
Reductions
of Carrying Value of Oil and Gas Properties
During 2009, 2008 and 2007, Devon reduced the carrying values of
certain of its oil and gas properties that are now held for
sale. These reductions primarily resulted from full cost ceiling
limitations. A summary of these reductions and additional
discussion is provided below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
Net of
|
|
|
|
|
|
Net of
|
|
|
|
|
|
Net of
|
|
|
|
Gross
|
|
|
Taxes
|
|
|
Gross
|
|
|
Taxes
|
|
|
Gross
|
|
|
Taxes
|
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
Brazil
|
|
$
|
103
|
|
|
$
|
103
|
|
|
$
|
437
|
|
|
$
|
437
|
|
|
$
|
|
|
|
$
|
|
|
Nigeria
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
68
|
|
|
|
13
|
|
Other
|
|
|
5
|
|
|
|
2
|
|
|
|
57
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
108
|
|
|
$
|
105
|
|
|
$
|
494
|
|
|
$
|
465
|
|
|
$
|
68
|
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brazils 2009 reduction resulted largely from an
exploratory well drilled at the BM-BAR-3 block in the offshore
Barreirinhas Basin. After drilling this well in the first
quarter of 2009, Devon concluded that the well did not have
adequate reserves for commercial viability. As a result, the
seismic, leasehold and drilling costs associated with this well
contributed to the reduction recognized in the first quarter of
2009.
120
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Brazils 2008 reduction was recognized in the fourth
quarter of 2008 and resulted primarily from a significant
decrease in its full cost ceiling. The lower ceiling value
largely resulted from the effects of sharp declines in oil
prices compared to previous quarter-end prices.
Based on unsuccessful drilling activities in Nigeria, Devon
reduced the carrying value of its Nigerian oil and gas
properties in 2007.
|
|
19.
|
(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
2009, 2008 and 2007. Because a net loss from continuing
operations was incurred during 2009 and 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 2009 and 2008 consolidated
statements of operations are the same as the basic loss per
share amounts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)
|
|
|
|
(Loss)
|
|
|
Common
|
|
|
Earnings
|
|
|
|
Earnings
|
|
|
Shares
|
|
|
per Share
|
|
|
|
(In millions, except per share amounts)
|
|
|
Year Ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
|
|
$
|
(2,753
|
)
|
|
|
444
|
|
|
|
|
|
Attributable to participating securities
|
|
|
31
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted loss per share
|
|
$
|
(2,722
|
)
|
|
|
439
|
|
|
$
|
(6.20
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
|
|
$
|
(3,039
|
)
|
|
|
444
|
|
|
|
|
|
Attributable to participating securities
|
|
|
31
|
|
|
|
(5
|
)
|
|
|
|
|
Less preferred stock dividends
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted loss per share
|
|
$
|
(3,013
|
)
|
|
|
439
|
|
|
$
|
(6.86
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations
|
|
$
|
2,485
|
|
|
|
445
|
|
|
|
|
|
Attributable to participating securities
|
|
|
(23
|
)
|
|
|
(4
|
)
|
|
|
|
|
Less preferred stock dividends
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share
|
|
|
2,452
|
|
|
|
441
|
|
|
$
|
5.56
|
|
Dilutive effect of potential common shares issuable upon the
exercise of outstanding stock options
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share
|
|
$
|
2,452
|
|
|
|
446
|
|
|
$
|
5.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Certain options to purchase shares of Devons common stock
were excluded from the dilution calculations because the options
were antidilutive. These excluded options totaled
9 million, 5 million and 2 million in 2009, 2008
and 2007, respectively.
Devon manages its operations through seven distinct operating
segments, or divisions, which are defined primarily by
geographic areas. For financial reporting purposes, Devon
aggregates its United States divisions into one reporting
segment due to the similar nature of the business. However,
Devons Canadian and
121
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
International divisions are reported as separate reporting
segments primarily due to significant differences in the
respective regulatory environments.
Devons segments are all primarily engaged in oil and gas
producing activities, and certain information regarding such
activities for each segment is included in Note 22.
Following is certain financial information regarding
Devons segments for 2009, 2008 and 2007. The revenues
reported are all from external customers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Canada
|
|
|
International
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
As of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets, including current assets held for sale
|
|
$
|
1,449
|
|
|
$
|
886
|
|
|
$
|
657
|
|
|
$
|
2,992
|
|
Property and equipment, net
|
|
|
13,199
|
|
|
|
5,568
|
|
|
|
|
|
|
|
18,767
|
|
Goodwill
|
|
|
3,046
|
|
|
|
2,884
|
|
|
|
|
|
|
|
5,930
|
|
Other assets, including long-term assets held for sale
|
|
|
674
|
|
|
|
73
|
|
|
|
1,250
|
|
|
|
1,997
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
18,368
|
|
|
$
|
9,411
|
|
|
$
|
1,907
|
|
|
$
|
29,686
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities, including current liabilities held for sale
|
|
$
|
2,993
|
|
|
$
|
575
|
|
|
$
|
234
|
|
|
$
|
3,802
|
|
Long-term debt
|
|
|
2,866
|
|
|
|
2,981
|
|
|
|
|
|
|
|
5,847
|
|
Asset retirement obligations, long-term
|
|
|
754
|
|
|
|
664
|
|
|
|
|
|
|
|
1,418
|
|
Other liabilities, including long-term liabilities held for sale
|
|
|
890
|
|
|
|
47
|
|
|
|
213
|
|
|
|
1,150
|
|
Deferred income taxes
|
|
|
860
|
|
|
|
1,039
|
|
|
|
|
|
|
|
1,899
|
|
Stockholders equity
|
|
|
10,005
|
|
|
|
4,105
|
|
|
|
1,460
|
|
|
|
15,570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
18,368
|
|
|
$
|
9,411
|
|
|
$
|
1,907
|
|
|
$
|
29,686
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
122
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Canada
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Year Ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales
|
|
$
|
3,958
|
|
|
$
|
2,139
|
|
|
$
|
6,097
|
|
Net gain on oil and gas derivative financial instruments
|
|
|
382
|
|
|
|
2
|
|
|
|
384
|
|
Marketing and midstream revenues
|
|
|
1,498
|
|
|
|
36
|
|
|
|
1,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
5,838
|
|
|
|
2,177
|
|
|
|
8,015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
997
|
|
|
|
673
|
|
|
|
1,670
|
|
Taxes other than income taxes
|
|
|
278
|
|
|
|
36
|
|
|
|
314
|
|
Marketing and midstream operating costs and expenses
|
|
|
1,004
|
|
|
|
18
|
|
|
|
1,022
|
|
Depreciation, depletion and amortization of oil and gas
properties
|
|
|
1,247
|
|
|
|
585
|
|
|
|
1,832
|
|
Depreciation and amortization of non-oil and gas properties
|
|
|
251
|
|
|
|
25
|
|
|
|
276
|
|
Accretion of asset retirement obligations
|
|
|
53
|
|
|
|
38
|
|
|
|
91
|
|
General and administrative expenses
|
|
|
529
|
|
|
|
119
|
|
|
|
648
|
|
Restructuring costs
|
|
|
105
|
|
|
|
|
|
|
|
105
|
|
Interest expense
|
|
|
125
|
|
|
|
224
|
|
|
|
349
|
|
Change in fair value of other financial instruments
|
|
|
(106
|
)
|
|
|
|
|
|
|
(106
|
)
|
Reduction of carrying value of oil and gas properties
|
|
|
6,408
|
|
|
|
|
|
|
|
6,408
|
|
Other (income) expense, net
|
|
|
(92
|
)
|
|
|
24
|
|
|
|
(68
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net
|
|
|
10,799
|
|
|
|
1,742
|
|
|
|
12,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations before income taxes
|
|
|
(4,961
|
)
|
|
|
435
|
|
|
|
(4,526
|
)
|
Income tax (benefit) expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
63
|
|
|
|
178
|
|
|
|
241
|
|
Deferred
|
|
|
(1,957
|
)
|
|
|
(57
|
)
|
|
|
(2,014
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax (benefit) expense
|
|
|
(1,894
|
)
|
|
|
121
|
|
|
|
(1,773
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
$
|
(3,067
|
)
|
|
$
|
314
|
|
|
$
|
(2,753
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset retirement
obligations
|
|
$
|
3,536
|
|
|
$
|
1,114
|
|
|
$
|
4,650
|
|
Revision of future asset retirement obligations
|
|
|
48
|
|
|
|
(15
|
)
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations
|
|
$
|
3,584
|
|
|
$
|
1,099
|
|
|
$
|
4,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
123
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Canada
|
|
|
International
|
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
As of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets, including current assets held for sale
|
|
$
|
1,925
|
|
|
$
|
367
|
|
|
$
|
392
|
|
|
$
|
2,684
|
|
Property and equipment, net
|
|
|
17,676
|
|
|
|
4,355
|
|
|
|
|
|
|
|
22,031
|
|
Goodwill
|
|
|
3,046
|
|
|
|
2,465
|
|
|
|
|
|
|
|
5,511
|
|
Other assets, including long-term assets held for sale
|
|
|
482
|
|
|
|
72
|
|
|
|
1,128
|
|
|
|
1,682
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
23,129
|
|
|
$
|
7,259
|
|
|
$
|
1,520
|
|
|
$
|
31,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities, including current liabilities held for sale
|
|
$
|
2,227
|
|
|
$
|
543
|
|
|
$
|
365
|
|
|
$
|
3,135
|
|
Long-term debt
|
|
|
2,683
|
|
|
|
2,978
|
|
|
|
|
|
|
|
5,661
|
|
Asset retirement obligations, long-term
|
|
|
694
|
|
|
|
555
|
|
|
|
|
|
|
|
1,249
|
|
Other liabilities, including long-term liabilities held for sale
|
|
|
983
|
|
|
|
40
|
|
|
|
166
|
|
|
|
1,189
|
|
Deferred income taxes
|
|
|
2,734
|
|
|
|
880
|
|
|
|
|
|
|
|
3,614
|
|
Stockholders equity
|
|
|
13,808
|
|
|
|
2,263
|
|
|
|
989
|
|
|
|
17,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
23,129
|
|
|
$
|
7,259
|
|
|
$
|
1,520
|
|
|
$
|
31,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
124
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Canada
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Year Ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales
|
|
$
|
8,206
|
|
|
$
|
3,514
|
|
|
$
|
11,720
|
|
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
|
|
|
|
13,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
1,075
|
|
|
|
776
|
|
|
|
1,851
|
|
Taxes other than income taxes
|
|
|
438
|
|
|
|
38
|
|
|
|
476
|
|
Marketing and midstream operating costs and expenses
|
|
|
1,593
|
|
|
|
18
|
|
|
|
1,611
|
|
Depreciation, depletion and amortization of oil and gas
properties
|
|
|
1,998
|
|
|
|
950
|
|
|
|
2,948
|
|
Depreciation and amortization of non-oil and gas Properties
|
|
|
229
|
|
|
|
26
|
|
|
|
255
|
|
Accretion of asset retirement obligations
|
|
|
42
|
|
|
|
38
|
|
|
|
80
|
|
General and administrative expenses
|
|
|
513
|
|
|
|
132
|
|
|
|
645
|
|
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
|
|
|
|
9,891
|
|
Other income, net
|
|
|
(203
|
)
|
|
|
(14
|
)
|
|
|
(217
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net
|
|
|
12,489
|
|
|
|
5,529
|
|
|
|
18,018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations before income taxes
|
|
|
(2,190
|
)
|
|
|
(1,970
|
)
|
|
|
(4,160
|
)
|
Income tax (benefit) expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
289
|
|
|
|
152
|
|
|
|
441
|
|
Deferred
|
|
|
(940
|
)
|
|
|
(622
|
)
|
|
|
(1,562
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax benefit
|
|
|
(651
|
)
|
|
|
(470
|
)
|
|
|
(1,121
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
|
|
$
|
(1,539
|
)
|
|
$
|
(1,500
|
)
|
|
$
|
(3,039
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset retirement
obligations
|
|
$
|
8,313
|
|
|
$
|
1,639
|
|
|
$
|
9,952
|
|
Revision of future asset retirement obligations
|
|
|
152
|
|
|
|
73
|
|
|
|
225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations
|
|
$
|
8,465
|
|
|
$
|
1,712
|
|
|
$
|
10,177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
125
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Canada
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales
|
|
$
|
5,814
|
|
|
$
|
2,411
|
|
|
$
|
8,225
|
|
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
|
|
|
|
9,975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
905
|
|
|
|
627
|
|
|
|
1,532
|
|
Taxes other than income taxes
|
|
|
327
|
|
|
|
31
|
|
|
|
358
|
|
Marketing and midstream operating costs and expenses
|
|
|
1,200
|
|
|
|
17
|
|
|
|
1,217
|
|
Depreciation, depletion and amortization of oil and gas
properties
|
|
|
1,672
|
|
|
|
740
|
|
|
|
2,412
|
|
Depreciation and amortization of non-oil and gas properties
|
|
|
180
|
|
|
|
21
|
|
|
|
201
|
|
Accretion of asset retirement obligations
|
|
|
38
|
|
|
|
32
|
|
|
|
70
|
|
General and administrative expenses
|
|
|
395
|
|
|
|
118
|
|
|
|
513
|
|
Interest expense
|
|
|
228
|
|
|
|
202
|
|
|
|
430
|
|
Change in fair value of other financial instruments
|
|
|
(32
|
)
|
|
|
(2
|
)
|
|
|
(34
|
)
|
Other income, net
|
|
|
(34
|
)
|
|
|
(17
|
)
|
|
|
(51
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net
|
|
|
4,879
|
|
|
|
1,769
|
|
|
|
6,648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes
|
|
|
2,642
|
|
|
|
685
|
|
|
|
3,327
|
|
Income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
100
|
|
|
|
135
|
|
|
|
235
|
|
Deferred
|
|
|
773
|
|
|
|
(166
|
)
|
|
|
607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit)
|
|
|
873
|
|
|
|
(31
|
)
|
|
|
842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations
|
|
$
|
1,769
|
|
|
$
|
716
|
|
|
$
|
2,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset retirement
obligations
|
|
$
|
4,522
|
|
|
$
|
1,350
|
|
|
$
|
5,872
|
|
Revision of future asset retirement obligations
|
|
|
210
|
|
|
|
99
|
|
|
|
309
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations
|
|
$
|
4,732
|
|
|
$
|
1,449
|
|
|
$
|
6,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
126
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
21.
|
Supplemental
Information to Statements of Cash Flows
|
Additional information related to Devons 2009, 2008 and
2007 statements of cash flows are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Net decrease (increase) in working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease (increase) in accounts receivable
|
|
$
|
142
|
|
|
$
|
187
|
|
|
$
|
(286
|
)
|
Decrease (increase) in other current assets
|
|
|
212
|
|
|
|
(46
|
)
|
|
|
(31
|
)
|
(Decrease) increase in accounts payable
|
|
|
(91
|
)
|
|
|
159
|
|
|
|
45
|
|
Increase in revenues and royalties due to others
|
|
|
|
|
|
|
11
|
|
|
|
79
|
|
Decrease in income taxes payable
|
|
|
(48
|
)
|
|
|
(309
|
)
|
|
|
(80
|
)
|
Decrease in other current liabilities
|
|
|
(66
|
)
|
|
|
(209
|
)
|
|
|
(239
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decreases (increase) in working capital
|
|
$
|
149
|
|
|
$
|
(207
|
)
|
|
$
|
(512
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary cash flow data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid (net of capitalized interest)
|
|
$
|
314
|
|
|
$
|
336
|
|
|
$
|
406
|
|
Income taxes paid (continuing and discontinued operations)
|
|
$
|
68
|
|
|
$
|
1,436
|
|
|
$
|
588
|
|
Noncash investing activity exchange of investment in
Chevron common stock for oil and gas properties
|
|
$
|
|
|
|
$
|
610
|
|
|
$
|
|
|
|
|
22.
|
Supplemental
Information on Oil and Gas Operations (Unaudited)
|
Supplemental unaudited information regarding Devons oil
and gas activities is presented in this note. The information is
provided separately by country and continent. Additionally, the
costs incurred and reserves information for the United States is
segregated between Devons onshore and offshore operations.
Unless otherwise noted, this supplemental information excludes
amounts for all periods presented related to Devons
discontinued operations.
Costs
Incurred
The following tables reflect the costs incurred in oil and gas
property acquisition, exploration, and development activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
U.S.
|
|
|
U.S.
|
|
|
Total
|
|
|
|
|
|
North
|
|
|
|
Onshore
|
|
|
Offshore
|
|
|
U.S.
|
|
|
Canada
|
|
|
America
|
|
|
|
(In millions)
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
17
|
|
|
$
|
|
|
|
$
|
17
|
|
|
$
|
18
|
|
|
$
|
35
|
|
Unproved properties
|
|
|
52
|
|
|
|
11
|
|
|
|
63
|
|
|
|
72
|
|
|
|
135
|
|
Exploration costs
|
|
|
122
|
|
|
|
260
|
|
|
|
382
|
|
|
|
152
|
|
|
|
534
|
|
Development costs
|
|
|
2,011
|
|
|
|
537
|
|
|
|
2,548
|
|
|
|
835
|
|
|
|
3,383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred
|
|
$
|
2,202
|
|
|
$
|
808
|
|
|
$
|
3,010
|
|
|
$
|
1,077
|
|
|
$
|
4,087
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
127
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
U.S.
|
|
|
U.S.
|
|
|
Total
|
|
|
|
|
|
North
|
|
|
|
Onshore
|
|
|
Offshore
|
|
|
U.S.
|
|
|
Canada
|
|
|
America
|
|
|
|
(In millions)
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
822
|
|
|
$
|
|
|
|
$
|
822
|
|
|
$
|
|
|
|
$
|
822
|
|
Unproved properties
|
|
|
1,226
|
|
|
|
185
|
|
|
|
1,411
|
|
|
|
352
|
|
|
|
1,763
|
|
Exploration costs
|
|
|
206
|
|
|
|
638
|
|
|
|
844
|
|
|
|
173
|
|
|
|
1,017
|
|
Development costs
|
|
|
4,182
|
|
|
|
551
|
|
|
|
4,733
|
|
|
|
1,131
|
|
|
|
5,864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred
|
|
$
|
6,436
|
|
|
$
|
1,374
|
|
|
$
|
7,810
|
|
|
$
|
1,656
|
|
|
$
|
9,466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
U.S.
|
|
|
U.S.
|
|
|
Total
|
|
|
|
|
|
North
|
|
|
|
Onshore
|
|
|
Offshore
|
|
|
U.S.
|
|
|
Canada
|
|
|
America
|
|
|
|
(In millions)
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
3
|
|
|
$
|
|
|
|
$
|
3
|
|
|
$
|
7
|
|
|
$
|
10
|
|
Unproved properties
|
|
|
77
|
|
|
|
79
|
|
|
|
156
|
|
|
|
49
|
|
|
|
205
|
|
Exploration costs
|
|
|
195
|
|
|
|
374
|
|
|
|
569
|
|
|
|
211
|
|
|
|
780
|
|
Development costs
|
|
|
3,183
|
|
|
|
359
|
|
|
|
3,542
|
|
|
|
1,098
|
|
|
|
4,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred
|
|
$
|
3,458
|
|
|
$
|
812
|
|
|
$
|
4,270
|
|
|
$
|
1,365
|
|
|
$
|
5,635
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
$332 million, $337 million and $277 million in
the years 2009, 2008 and 2007, 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
$74 million, $71 million and $48 million in the
years 2009, 2008 and 2007, respectively.
Results
of Operations
The following tables include revenues and expenses directly
associated with Devons 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. Income tax
128
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
United States
|
|
|
Canada
|
|
|
North America
|
|
|
|
(In millions)
|
|
|
Oil, gas and NGL sales
|
|
$
|
3,958
|
|
|
$
|
2,139
|
|
|
$
|
6,097
|
|
Lease operating expenses
|
|
|
(997
|
)
|
|
|
(673
|
)
|
|
|
(1,670
|
)
|
Taxes other than income taxes
|
|
|
(258
|
)
|
|
|
(35
|
)
|
|
|
(293
|
)
|
Depreciation, depletion and amortization
|
|
|
(1,247
|
)
|
|
|
(585
|
)
|
|
|
(1,832
|
)
|
Accretion of asset retirement obligations
|
|
|
(53
|
)
|
|
|
(38
|
)
|
|
|
(91
|
)
|
General and administrative expenses
|
|
|
(145
|
)
|
|
|
(74
|
)
|
|
|
(219
|
)
|
Reduction of carrying value of oil and gas properties
|
|
|
(6,408
|
)
|
|
|
|
|
|
|
(6,408
|
)
|
Income tax benefit (expense)
|
|
|
1,800
|
|
|
|
(220
|
)
|
|
|
1,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
(3,350
|
)
|
|
$
|
514
|
|
|
$
|
(2,836
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization per Boe
|
|
$
|
7.47
|
|
|
$
|
8.84
|
|
|
$
|
7.86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
United States
|
|
|
Canada
|
|
|
North America
|
|
|
|
(In millions)
|
|
|
Oil, gas and NGL sales
|
|
$
|
8,206
|
|
|
$
|
3,514
|
|
|
$
|
11,720
|
|
Lease operating expenses
|
|
|
(1,075
|
)
|
|
|
(776
|
)
|
|
|
(1,851
|
)
|
Taxes other than income taxes
|
|
|
(420
|
)
|
|
|
(37
|
)
|
|
|
(457
|
)
|
Depreciation, depletion and amortization
|
|
|
(1,998
|
)
|
|
|
(950
|
)
|
|
|
(2,948
|
)
|
Accretion of asset retirement obligations
|
|
|
(42
|
)
|
|
|
(38
|
)
|
|
|
(80
|
)
|
General and administrative expenses
|
|
|
(148
|
)
|
|
|
(87
|
)
|
|
|
(235
|
)
|
Reduction of carrying value of oil and gas properties
|
|
|
(6,538
|
)
|
|
|
(3,353
|
)
|
|
|
(9,891
|
)
|
Income tax benefit
|
|
|
719
|
|
|
|
405
|
|
|
|
1,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
(1,296
|
)
|
|
$
|
(1,322
|
)
|
|
$
|
(2,618
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization per Boe
|
|
$
|
12.31
|
|
|
$
|
15.59
|
|
|
$
|
13.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
United States
|
|
|
Canada
|
|
|
North America
|
|
|
|
(In millions)
|
|
|
Oil, gas and NGL sales
|
|
$
|
5,814
|
|
|
$
|
2,411
|
|
|
$
|
8,225
|
|
Lease operating expenses
|
|
|
(905
|
)
|
|
|
(627
|
)
|
|
|
(1,532
|
)
|
Taxes other than income taxes
|
|
|
(312
|
)
|
|
|
(31
|
)
|
|
|
(343
|
)
|
Depreciation, depletion and amortization
|
|
|
(1,672
|
)
|
|
|
(740
|
)
|
|
|
(2,412
|
)
|
Accretion of asset retirement obligations
|
|
|
(38
|
)
|
|
|
(32
|
)
|
|
|
(70
|
)
|
General and administrative expenses
|
|
|
(143
|
)
|
|
|
(76
|
)
|
|
|
(219
|
)
|
Income tax expense
|
|
|
(966
|
)
|
|
|
(49
|
)
|
|
|
(1,015
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
1,778
|
|
|
$
|
856
|
|
|
$
|
2,634
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization per Boe
|
|
$
|
11.44
|
|
|
$
|
12.73
|
|
|
$
|
11.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
129
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In 2007, the total and Canadian income tax amounts in the table
above were reduced by $261 million due to statutory rate
reductions that were enacted in that year.
Proved
Reserves
The following tables present Devons estimated proved
developed and proved undeveloped reserves by product for each
significant country for the three years ended December 31,
2009. The significant changes in Devons reserves are
discussed following the tables.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls)
|
|
|
|
U.S.
|
|
|
U.S.
|
|
|
Total
|
|
|
|
|
|
North
|
|
|
|
Onshore
|
|
|
Offshore
|
|
|
U.S.
|
|
|
Canada
|
|
|
America
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
127
|
|
|
|
43
|
|
|
|
170
|
|
|
|
329
|
|
|
|
499
|
|
Revisions due to prices
|
|
|
4
|
|
|
|
|
|
|
|
4
|
|
|
|
16
|
|
|
|
20
|
|
Revisions other than price
|
|
|
3
|
|
|
|
3
|
|
|
|
6
|
|
|
|
13
|
|
|
|
19
|
|
Extensions and discoveries
|
|
|
8
|
|
|
|
1
|
|
|
|
9
|
|
|
|
46
|
|
|
|
55
|
|
Purchase of reserves
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
Production
|
|
|
(11
|
)
|
|
|
(8
|
)
|
|
|
(19
|
)
|
|
|
(16
|
)
|
|
|
(35
|
)
|
Sale of reserves
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
131
|
|
|
|
39
|
|
|
|
170
|
|
|
|
388
|
|
|
|
558
|
|
Revisions due to prices
|
|
|
(17
|
)
|
|
|
(3
|
)
|
|
|
(20
|
)
|
|
|
(349
|
)
|
|
|
(369
|
)
|
Revisions other than price
|
|
|
2
|
|
|
|
3
|
|
|
|
5
|
|
|
|
2
|
|
|
|
7
|
|
Extensions and discoveries
|
|
|
11
|
|
|
|
1
|
|
|
|
12
|
|
|
|
120
|
|
|
|
132
|
|
Purchase of reserves
|
|
|
18
|
|
|
|
|
|
|
|
18
|
|
|
|
|
|
|
|
18
|
|
Production
|
|
|
(11
|
)
|
|
|
(6
|
)
|
|
|
(17
|
)
|
|
|
(22
|
)
|
|
|
(39
|
)
|
Sale of reserves
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
(5
|
)
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
133
|
|
|
|
34
|
|
|
|
167
|
|
|
|
134
|
|
|
|
301
|
|
Revisions due to prices
|
|
|
9
|
|
|
|
2
|
|
|
|
11
|
|
|
|
291
|
|
|
|
302
|
|
Revisions other than price
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
(8
|
)
|
|
|
(7
|
)
|
Extensions and discoveries
|
|
|
9
|
|
|
|
2
|
|
|
|
11
|
|
|
|
122
|
|
|
|
133
|
|
Purchase of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(12
|
)
|
|
|
(5
|
)
|
|
|
(17
|
)
|
|
|
(25
|
)
|
|
|
(42
|
)
|
Sale of reserves
|
|
|
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
139
|
|
|
|
33
|
|
|
|
172
|
|
|
|
514
|
|
|
|
686
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
116
|
|
|
|
31
|
|
|
|
147
|
|
|
|
112
|
|
|
|
259
|
|
December 31, 2007
|
|
|
122
|
|
|
|
26
|
|
|
|
148
|
|
|
|
195
|
|
|
|
343
|
|
December 31, 2008
|
|
|
111
|
|
|
|
22
|
|
|
|
133
|
|
|
|
110
|
|
|
|
243
|
|
December 31, 2009
|
|
|
119
|
|
|
|
21
|
|
|
|
140
|
|
|
|
149
|
|
|
|
289
|
|
Proved undeveloped reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
11
|
|
|
|
12
|
|
|
|
23
|
|
|
|
217
|
|
|
|
240
|
|
December 31, 2007
|
|
|
9
|
|
|
|
13
|
|
|
|
22
|
|
|
|
193
|
|
|
|
215
|
|
December 31, 2008
|
|
|
22
|
|
|
|
12
|
|
|
|
34
|
|
|
|
24
|
|
|
|
58
|
|
December 31, 2009
|
|
|
20
|
|
|
|
12
|
|
|
|
32
|
|
|
|
365
|
|
|
|
397
|
|
130
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Bcf)
|
|
|
|
U.S.
|
|
|
U.S.
|
|
|
Total
|
|
|
|
|
|
North
|
|
|
|
Onshore
|
|
|
Offshore
|
|
|
U.S.
|
|
|
Canada
|
|
|
America
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
5,979
|
|
|
|
376
|
|
|
|
6,355
|
|
|
|
1,896
|
|
|
|
8,251
|
|
Revisions due to prices
|
|
|
117
|
|
|
|
2
|
|
|
|
119
|
|
|
|
50
|
|
|
|
169
|
|
Revisions other than price
|
|
|
175
|
|
|
|
(1
|
)
|
|
|
174
|
|
|
|
(19
|
)
|
|
|
155
|
|
Extensions and discoveries
|
|
|
1,055
|
|
|
|
78
|
|
|
|
1,133
|
|
|
|
139
|
|
|
|
1,272
|
|
Purchase of reserves
|
|
|
10
|
|
|
|
|
|
|
|
10
|
|
|
|
5
|
|
|
|
15
|
|
Production
|
|
|
(558
|
)
|
|
|
(77
|
)
|
|
|
(635
|
)
|
|
|
(227
|
)
|
|
|
(862
|
)
|
Sale of reserves
|
|
|
(13
|
)
|
|
|
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
6,765
|
|
|
|
378
|
|
|
|
7,143
|
|
|
|
1,844
|
|
|
|
8,987
|
|
Revisions due to prices
|
|
|
(367
|
)
|
|
|
(2
|
)
|
|
|
(369
|
)
|
|
|
(219
|
)
|
|
|
(588
|
)
|
Revisions other than price
|
|
|
85
|
|
|
|
21
|
|
|
|
106
|
|
|
|
(12
|
)
|
|
|
94
|
|
Extensions and discoveries
|
|
|
1,916
|
|
|
|
50
|
|
|
|
1,966
|
|
|
|
111
|
|
|
|
2,077
|
|
Purchase of reserves
|
|
|
250
|
|
|
|
|
|
|
|
250
|
|
|
|
2
|
|
|
|
252
|
|
Production
|
|
|
(669
|
)
|
|
|
(57
|
)
|
|
|
(726
|
)
|
|
|
(212
|
)
|
|
|
(938
|
)
|
Sale of reserves
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
(4
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
7,979
|
|
|
|
390
|
|
|
|
8,369
|
|
|
|
1,510
|
|
|
|
9,879
|
|
Revisions due to prices
|
|
|
(661
|
)
|
|
|
(4
|
)
|
|
|
(665
|
)
|
|
|
(29
|
)
|
|
|
(694
|
)
|
Revisions other than price
|
|
|
119
|
|
|
|
(62
|
)
|
|
|
57
|
|
|
|
(14
|
)
|
|
|
43
|
|
Extensions and discoveries
|
|
|
1,387
|
|
|
|
64
|
|
|
|
1,451
|
|
|
|
67
|
|
|
|
1,518
|
|
Purchase of reserves
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
6
|
|
|
|
7
|
|
Production
|
|
|
(698
|
)
|
|
|
(45
|
)
|
|
|
(743
|
)
|
|
|
(223
|
)
|
|
|
(966
|
)
|
Sale of reserves
|
|
|
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
(29
|
)
|
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
8,127
|
|
|
|
342
|
|
|
|
8,469
|
|
|
|
1,288
|
|
|
|
9,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
4,672
|
|
|
|
244
|
|
|
|
4,916
|
|
|
|
1,560
|
|
|
|
6,476
|
|
December 31, 2007
|
|
|
5,547
|
|
|
|
196
|
|
|
|
5,743
|
|
|
|
1,506
|
|
|
|
7,249
|
|
December 31, 2008
|
|
|
6,469
|
|
|
|
212
|
|
|
|
6,681
|
|
|
|
1,357
|
|
|
|
8,038
|
|
December 31, 2009
|
|
|
6,447
|
|
|
|
185
|
|
|
|
6,632
|
|
|
|
1,213
|
|
|
|
7,845
|
|
Proved undeveloped reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
1,307
|
|
|
|
132
|
|
|
|
1,439
|
|
|
|
336
|
|
|
|
1,775
|
|
December 31, 2007
|
|
|
1,218
|
|
|
|
182
|
|
|
|
1,400
|
|
|
|
338
|
|
|
|
1,738
|
|
December 31, 2008
|
|
|
1,510
|
|
|
|
178
|
|
|
|
1,688
|
|
|
|
153
|
|
|
|
1,841
|
|
December 31, 2009
|
|
|
1,680
|
|
|
|
157
|
|
|
|
1,837
|
|
|
|
75
|
|
|
|
1,912
|
|
131
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids (MMBbls)
|
|
|
|
U.S.
|
|
|
U.S.
|
|
|
Total
|
|
|
|
|
|
North
|
|
|
|
Onshore
|
|
|
Offshore
|
|
|
U.S.
|
|
|
Canada
|
|
|
America
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
230
|
|
|
|
3
|
|
|
|
233
|
|
|
|
42
|
|
|
|
275
|
|
Revisions due to prices
|
|
|
5
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
5
|
|
Revisions other than price
|
|
|
22
|
|
|
|
(1
|
)
|
|
|
21
|
|
|
|
(1
|
)
|
|
|
20
|
|
Extensions and discoveries
|
|
|
45
|
|
|
|
|
|
|
|
45
|
|
|
|
2
|
|
|
|
47
|
|
Purchase of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(21
|
)
|
|
|
(1
|
)
|
|
|
(22
|
)
|
|
|
(4
|
)
|
|
|
(26
|
)
|
Sale of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
281
|
|
|
|
1
|
|
|
|
282
|
|
|
|
39
|
|
|
|
321
|
|
Revisions due to prices
|
|
|
(18
|
)
|
|
|
|
|
|
|
(18
|
)
|
|
|
(2
|
)
|
|
|
(20
|
)
|
Revisions other than price
|
|
|
5
|
|
|
|
1
|
|
|
|
6
|
|
|
|
|
|
|
|
6
|
|
Extensions and discoveries
|
|
|
65
|
|
|
|
|
|
|
|
65
|
|
|
|
2
|
|
|
|
67
|
|
Purchase of reserves
|
|
|
6
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
6
|
|
Production
|
|
|
(24
|
)
|
|
|
|
|
|
|
(24
|
)
|
|
|
(4
|
)
|
|
|
(28
|
)
|
Sale of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
315
|
|
|
|
2
|
|
|
|
317
|
|
|
|
35
|
|
|
|
352
|
|
Revisions due to prices
|
|
|
(11
|
)
|
|
|
|
|
|
|
(11
|
)
|
|
|
2
|
|
|
|
(9
|
)
|
Revisions other than price
|
|
|
36
|
|
|
|
1
|
|
|
|
37
|
|
|
|
|
|
|
|
37
|
|
Extensions and discoveries
|
|
|
70
|
|
|
|
|
|
|
|
70
|
|
|
|
1
|
|
|
|
71
|
|
Purchase of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(25
|
)
|
|
|
(1
|
)
|
|
|
(26
|
)
|
|
|
(4
|
)
|
|
|
(30
|
)
|
Sale of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
385
|
|
|
|
2
|
|
|
|
387
|
|
|
|
34
|
|
|
|
421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
194
|
|
|
|
2
|
|
|
|
196
|
|
|
|
33
|
|
|
|
229
|
|
December 31, 2007
|
|
|
243
|
|
|
|
1
|
|
|
|
244
|
|
|
|
30
|
|
|
|
274
|
|
December 31, 2008
|
|
|
260
|
|
|
|
1
|
|
|
|
261
|
|
|
|
31
|
|
|
|
292
|
|
December 31, 2009
|
|
|
293
|
|
|
|
1
|
|
|
|
294
|
|
|
|
32
|
|
|
|
326
|
|
Proved undeveloped reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
36
|
|
|
|
1
|
|
|
|
37
|
|
|
|
9
|
|
|
|
46
|
|
December 31, 2007
|
|
|
38
|
|
|
|
|
|
|
|
38
|
|
|
|
9
|
|
|
|
47
|
|
December 31, 2008
|
|
|
55
|
|
|
|
1
|
|
|
|
56
|
|
|
|
4
|
|
|
|
60
|
|
December 31, 2009
|
|
|
92
|
|
|
|
1
|
|
|
|
93
|
|
|
|
2
|
|
|
|
95
|
|
132
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMBoe)(1)
|
|
|
|
U.S.
|
|
|
U.S.
|
|
|
Total
|
|
|
|
|
|
North
|
|
|
|
Onshore
|
|
|
Offshore
|
|
|
U.S.
|
|
|
Canada
|
|
|
America
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
1,353
|
|
|
|
109
|
|
|
|
1,462
|
|
|
|
687
|
|
|
|
2,149
|
|
Revisions due to prices
|
|
|
28
|
|
|
|
1
|
|
|
|
29
|
|
|
|
25
|
|
|
|
54
|
|
Revisions other than price
|
|
|
55
|
|
|
|
1
|
|
|
|
56
|
|
|
|
7
|
|
|
|
63
|
|
Extensions and discoveries
|
|
|
228
|
|
|
|
14
|
|
|
|
242
|
|
|
|
72
|
|
|
|
314
|
|
Purchase of reserves
|
|
|
2
|
|
|
|
|
|
|
|
2
|
|
|
|
1
|
|
|
|
3
|
|
Production
|
|
|
(124
|
)
|
|
|
(22
|
)
|
|
|
(146
|
)
|
|
|
(58
|
)
|
|
|
(204
|
)
|
Sale of reserves
|
|
|
(3
|
)
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
1,539
|
|
|
|
103
|
|
|
|
1,642
|
|
|
|
734
|
|
|
|
2,376
|
|
Revisions due to prices
|
|
|
(97
|
)
|
|
|
(3
|
)
|
|
|
(100
|
)
|
|
|
(387
|
)
|
|
|
(487
|
)
|
Revisions other than price
|
|
|
21
|
|
|
|
7
|
|
|
|
28
|
|
|
|
|
|
|
|
28
|
|
Extensions and discoveries
|
|
|
395
|
|
|
|
10
|
|
|
|
405
|
|
|
|
141
|
|
|
|
546
|
|
Purchase of reserves
|
|
|
66
|
|
|
|
|
|
|
|
66
|
|
|
|
|
|
|
|
66
|
|
Production
|
|
|
(146
|
)
|
|
|
(16
|
)
|
|
|
(162
|
)
|
|
|
(61
|
)
|
|
|
(223
|
)
|
Sale of reserves
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
(6
|
)
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
1,777
|
|
|
|
101
|
|
|
|
1,878
|
|
|
|
421
|
|
|
|
2,299
|
|
Revisions due to prices
|
|
|
(113
|
)
|
|
|
1
|
|
|
|
(112
|
)
|
|
|
289
|
|
|
|
177
|
|
Revisions other than price
|
|
|
57
|
|
|
|
(8
|
)
|
|
|
49
|
|
|
|
(11
|
)
|
|
|
38
|
|
Extensions and discoveries
|
|
|
311
|
|
|
|
12
|
|
|
|
323
|
|
|
|
135
|
|
|
|
458
|
|
Purchase of reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
Production
|
|
|
(154
|
)
|
|
|
(13
|
)
|
|
|
(167
|
)
|
|
|
(66
|
)
|
|
|
(233
|
)
|
Sale of reserves
|
|
|
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
(6
|
)
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
1,878
|
|
|
|
92
|
|
|
|
1,970
|
|
|
|
763
|
|
|
|
2,733
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
1,089
|
|
|
|
74
|
|
|
|
1,163
|
|
|
|
405
|
|
|
|
1,568
|
|
December 31, 2007
|
|
|
1,290
|
|
|
|
59
|
|
|
|
1,349
|
|
|
|
476
|
|
|
|
1,825
|
|
December 31, 2008
|
|
|
1,449
|
|
|
|
59
|
|
|
|
1,508
|
|
|
|
367
|
|
|
|
1,875
|
|
December 31, 2009
|
|
|
1,486
|
|
|
|
53
|
|
|
|
1,539
|
|
|
|
383
|
|
|
|
1,922
|
|
Proved undeveloped reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
264
|
|
|
|
35
|
|
|
|
299
|
|
|
|
282
|
|
|
|
581
|
|
December 31, 2007
|
|
|
249
|
|
|
|
44
|
|
|
|
293
|
|
|
|
258
|
|
|
|
551
|
|
December 31, 2008
|
|
|
328
|
|
|
|
42
|
|
|
|
370
|
|
|
|
54
|
|
|
|
424
|
|
December 31, 2009
|
|
|
392
|
|
|
|
39
|
|
|
|
431
|
|
|
|
380
|
|
|
|
811
|
|
|
|
|
(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. This rate is not necessarily indicative of the
relationship of natural gas and oil prices. Natural gas liquids
reserves are converted to Boe on a
one-to-one
basis with oil. |
133
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
SECs
Modernization of Oil and Gas Reporting
At the end of 2009, Devon adopted the SECs
Modernization of Oil and Gas Reporting, as well as the
conforming rule changes issued by the Financial Accounting
Standards Board. Upon adoption, the two primary rule changes
that impacted Devons year-end reserves estimates were
those related to assumptions for pricing and reasonable
certainty.
The SECs prior rules required proved reserve estimates to
be calculated using prices as of the end of the period and held
constant over the life of the reserves. The revised rules
require reserves estimates to be calculated using an average of
the
first-day-of-the-month
price for the preceding
12-month
period.
The revised rules amend the definition of proved reserves to
permit the use of reliable technologies to establish the
reasonable certainty of proved reserves. This revision includes
provisions for establishing levels of lowest known hydrocarbons
and highest known oil through reliable technology other than
well penetrations. This revision also allows proved reserves to
be claimed beyond development spacing areas that are immediately
adjacent to developed spacing areas if economic producibility
can be established with reasonable certainty based on reliable
technologies. As a result of adopting these provisions of the
new rules, Devons 2009 reserves increased approximately
65 MMBoe, or 2%. This increase is included in the 2009
extensions and discoveries total.
Price
Revisions
2009 Reserves increased 177 MMBoe due to
higher oil prices, partially offset by lower gas prices. The
increase in oil reserves primarily related to Devons
Jackfish thermal heavy oil reserves in Canada. At the end of
2008, 331 MMBoe of reserves related to Jackfish were not
considered proved. However, due to higher prices, these reserves
were considered proved as of December 31, 2009.
Significantly lower gas prices caused Devons reserves to
decrease 116 MMBoe, which primarily related to its United
States reserves.
2008 Due to significantly lower oil, gas and
NGL prices as of December 31, 2008 compared to
December 31, 2007, 487 MMBoe of reserves were not
considered proved as of December 31, 2008. Of the
487 MMBoe price revisions, 331 MMBoe related to
Jackfish steam-assisted gravity drainage project in Canada.
The 487 MMBoe price revision also included 28 MMBoe
related to Devons proved reserves in the Canadian province
of Alberta. In December 2008, the provincial government of
Alberta enacted a new royalty regime. The new regime for
conventional oil, gas, NGL and heavy oil production was
effective January 1, 2009. As a result of the newly enacted
royalties, Devons proved reserves decreased as of
December 31, 2008.
Revisions
Other Than Price
The 2009 total revision included 48 MMBoe related to the
Barnett Shale. The 2008 total included performance revisions of
22 MMBoe in the Barnett Shale. The 2007 total included
performance revisions of 39 MMBoe at the Barnett Shale,
13 MMBoe at Jackfish and 13 MMBoe at Carthage.
Extensions
and Discoveries
2009 Of the 458 MMBoe of 2009 extensions
and discoveries, 204 MMBoe related to the Barnett Shale
area in Texas, 118 MMBoe related to Jackfish, 49 MMBoe
related to the Cana-Woodford Shale area in western Oklahoma,
14 MMBoe related to the Rocky Mountain area, 11 MMBoe
related to Deepwater Production in the Gulf, 8 MMBoe
related to the Carthage Conventional area in east Texas, and
7 MMBoe related to the Haynesville Shale area in east Texas.
134
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The 2009 extensions and discoveries included 371 MMBoe
related to additions from Devons infill drilling
activities, including 203 MMBoe at the Barnett Shale,
118 MMBoe at Jackfish and 24 MMBoe at the
Cana-Woodford Shale.
2008 Of the 546 MMBoe of 2008 extensions
and discoveries, 252 MMBoe related to the Barnett Shale,
101 MMBoe related to Jackfish, 44 MMBoe related to
Carthage Conventional, 21 MMBoe related to the
Cana-Woodford Shale, 19 MMBoe related to the Lloydminster
heavy oil development in Canada and 17 MMBoe related to the
Arkoma-Woodford Shale area in southeastern Oklahoma.
The 2008 extensions and discoveries included 420 MMBoe
related to additions from Devons infill drilling
activities, including 243 MMBoe at the Barnett Shale,
101 MMBoe at Jackfish, 22 MMBoe at Carthage
Conventional, 18 MMBoe at Lloydminster and 11 MMBoe at
the Cana-Woodford Shale.
2007 Of the 314 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
Arkoma-Woodford Shale.
The 2007 extensions and discoveries included 154 MMBoe
related to additions from Devons infill drilling
activities, including 96 MMBoe at the Barnett Shale and
19 MMBoe at Lloydminster.
Purchase
of Reserves
The 2008 total included 34 MMBoe located in Utah and
27 MMBoe located in the Permian Basin.
Prepared
and Audited 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 2009, 2008 and
2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Prepared
|
|
|
Audited
|
|
|
Prepared
|
|
|
Audited
|
|
|
Prepared
|
|
|
Audited
|
|
|
U.S. Onshore
|
|
|
|
|
|
|
93
|
%
|
|
|
|
|
|
|
92
|
%
|
|
|
|
|
|
|
88
|
%
|
U.S. Offshore
|
|
|
100
|
%
|
|
|
|
|
|
|
100
|
%
|
|
|
|
|
|
|
100
|
%
|
|
|
|
|
U.S.
|
|
|
5
|
%
|
|
|
89
|
%
|
|
|
5
|
%
|
|
|
87
|
%
|
|
|
6
|
%
|
|
|
82
|
%
|
Canada
|
|
|
|
|
|
|
91
|
%
|
|
|
|
|
|
|
78
|
%
|
|
|
34
|
%
|
|
|
51
|
%
|
North America
|
|
|
3
|
%
|
|
|
89
|
%
|
|
|
4
|
%
|
|
|
85
|
%
|
|
|
15
|
%
|
|
|
73
|
%
|
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.
135
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Standardized
Measure
The tables below reflect the standardized measure of discounted
future net cash flows related to Devons interest in proved
reserves.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
United States
|
|
|
Canada
|
|
|
North America
|
|
|
|
(In millions)
|
|
|
Future cash inflows
|
|
$
|
44,571
|
|
|
$
|
28,442
|
|
|
$
|
73,013
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
(6,814
|
)
|
|
|
(4,132
|
)
|
|
|
(10,946
|
)
|
Production
|
|
|
(22,184
|
)
|
|
|
(9,847
|
)
|
|
|
(32,031
|
)
|
Future income tax expense
|
|
|
(3,572
|
)
|
|
|
(3,408
|
)
|
|
|
(6,980
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
12,001
|
|
|
|
11,055
|
|
|
|
23,056
|
|
10% discount to reflect timing of cash flows
|
|
|
(6,121
|
)
|
|
|
(5,532
|
)
|
|
|
(11,653
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
5,880
|
|
|
$
|
5,523
|
|
|
$
|
11,403
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
United States
|
|
|
Canada
|
|
|
North America
|
|
|
|
(In millions)
|
|
|
Future cash inflows
|
|
$
|
51,284
|
|
|
$
|
11,459
|
|
|
$
|
62,743
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
(6,887
|
)
|
|
|
(1,623
|
)
|
|
|
(8,510
|
)
|
Production
|
|
|
(24,113
|
)
|
|
|
(5,742
|
)
|
|
|
(29,855
|
)
|
Future income tax expense
|
|
|
(5,585
|
)
|
|
|
(942
|
)
|
|
|
(6,527
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
14,699
|
|
|
|
3,152
|
|
|
|
17,851
|
|
10% discount to reflect timing of cash flows
|
|
|
(7,318
|
)
|
|
|
(1,140
|
)
|
|
|
(8,458
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
7,381
|
|
|
$
|
2,012
|
|
|
$
|
9,393
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
United States
|
|
|
Canada
|
|
|
North America
|
|
|
|
(In millions)
|
|
|
Future cash inflows
|
|
$
|
72,109
|
|
|
$
|
28,684
|
|
|
$
|
100,793
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
(5,673
|
)
|
|
|
(3,380
|
)
|
|
|
(9,053
|
)
|
Production
|
|
|
(24,606
|
)
|
|
|
(10,941
|
)
|
|
|
(35,547
|
)
|
Future income tax expense
|
|
|
(12,704
|
)
|
|
|
(3,570
|
)
|
|
|
(16,274
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
29,126
|
|
|
|
10,793
|
|
|
|
39,919
|
|
10% discount to reflect timing of cash flows
|
|
|
(14,312
|
)
|
|
|
(5,025
|
)
|
|
|
(19,337
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
14,814
|
|
|
$
|
5,768
|
|
|
$
|
20,582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows, development costs and production costs were
computed using the same assumptions for prices and costs that
were used to estimate Devons proved oil and gas reserves
at the end of each year. For 2009, the prices averaged $47.80
per barrel of oil, $3.12 per Mcf of gas and $22.78 per barrel of
natural
136
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
gas liquids. Of the $10.9 billion of future development
costs as of the end of 2009, $2.0 billion,
$1.6 billion and $0.9 billion are estimated to be
spent in 2010, 2011 and 2012, respectively.
Future development costs include not only development costs, but
also future dismantlement, abandonment and rehabilitation costs.
Included as part of the $10.9 billion of future development
costs are $1.1 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.
The principal changes in the standardized measure of discounted
future net cash flows attributable to Devons proved
reserves are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Beginning balance
|
|
$
|
9,393
|
|
|
$
|
20,582
|
|
|
$
|
13,474
|
|
Oil, gas and NGL sales, net of production costs
|
|
|
(3,915
|
)
|
|
|
(9,177
|
)
|
|
|
(6,131
|
)
|
Net changes in prices and production costs
|
|
|
(1,672
|
)
|
|
|
(13,839
|
)
|
|
|
7,896
|
|
Extensions and discoveries, net of future development costs
|
|
|
2,378
|
|
|
|
1,729
|
|
|
|
4,130
|
|
Purchase of reserves, net of future development costs
|
|
|
6
|
|
|
|
214
|
|
|
|
50
|
|
Development costs incurred that reduced future development costs
|
|
|
1,012
|
|
|
|
1,660
|
|
|
|
1,559
|
|
Revisions of quantity estimates
|
|
|
4,051
|
|
|
|
(1,294
|
)
|
|
|
564
|
|
Sales of reserves in place
|
|
|
(37
|
)
|
|
|
(2
|
)
|
|
|
(51
|
)
|
Accretion of discount
|
|
|
1,281
|
|
|
|
2,894
|
|
|
|
1,933
|
|
Net change in income taxes
|
|
|
(51
|
)
|
|
|
4,934
|
|
|
|
(2,494
|
)
|
Other, primarily changes in timing and foreign exchange rates
|
|
|
(1,043
|
)
|
|
|
1,692
|
|
|
|
(348
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
$
|
11,403
|
|
|
$
|
9,393
|
|
|
$
|
20,582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
137
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
23.
|
Supplemental
Quarterly Financial Information (Unaudited)
|
Following is a summary of the unaudited interim results of
operations for the years ended December 31, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Full
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year
|
|
|
|
(In millions, except per share amounts)
|
|
|
Revenues
|
|
$
|
1,900
|
|
|
$
|
1,822
|
|
|
$
|
1,848
|
|
|
$
|
2,445
|
|
|
$
|
8,015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
$
|
(3,882
|
)
|
|
$
|
190
|
|
|
$
|
382
|
|
|
|
557
|
|
|
$
|
(2,753
|
)
|
(Loss) earnings from discontinued operations
|
|
|
(77
|
)
|
|
|
124
|
|
|
|
117
|
|
|
|
110
|
|
|
|
274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(3,959
|
)
|
|
$
|
314
|
|
|
$
|
499
|
|
|
$
|
667
|
|
|
$
|
(2,479
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
$
|
(8.74
|
)
|
|
$
|
0.43
|
|
|
$
|
0.86
|
|
|
$
|
1.25
|
|
|
$
|
(6.20
|
)
|
(Loss) earnings from discontinued operations
|
|
|
(0.18
|
)
|
|
|
0.28
|
|
|
|
0.27
|
|
|
|
0.25
|
|
|
|
0.62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(8.92
|
)
|
|
$
|
0.71
|
|
|
$
|
1.13
|
|
|
$
|
1.50
|
|
|
$
|
(5.58
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net (loss) earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations
|
|
$
|
(8.74
|
)
|
|
$
|
0.42
|
|
|
$
|
0.86
|
|
|
$
|
1.25
|
|
|
$
|
(6.20
|
)
|
(Loss) earnings from discontinued operations
|
|
|
(0.18
|
)
|
|
|
0.28
|
|
|
|
0.26
|
|
|
|
0.24
|
|
|
|
0.62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings
|
|
$
|
(8.92
|
)
|
|
$
|
0.70
|
|
|
$
|
1.12
|
|
|
$
|
1.49
|
|
|
$
|
(5.58
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Full
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year
|
|
|
|
(In millions, except per share amounts)
|
|
|
Revenues
|
|
$
|
2,503
|
|
|
$
|
3,152
|
|
|
$
|
5,651
|
|
|
$
|
2,552
|
|
|
$
|
13,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations
|
|
$
|
415
|
|
|
$
|
423
|
|
|
$
|
2,393
|
|
|
|
(6,270
|
)
|
|
$
|
(3,039
|
)
|
Earnings (loss) from discontinued operations
|
|
|
334
|
|
|
|
878
|
|
|
|
225
|
|
|
|
(546
|
)
|
|
|
891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
$
|
749
|
|
|
$
|
1,301
|
|
|
$
|
2,618
|
|
|
$
|
(6,816
|
)
|
|
$
|
(2,148
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations
|
|
$
|
0.93
|
|
|
$
|
0.94
|
|
|
$
|
5.42
|
|
|
$
|
(14.19
|
)
|
|
$
|
(6.86
|
)
|
Earnings (loss) from discontinued operations
|
|
|
0.75
|
|
|
|
1.97
|
|
|
|
0.51
|
|
|
|
(1.23
|
)
|
|
|
2.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
$
|
1.68
|
|
|
$
|
2.91
|
|
|
$
|
5.93
|
|
|
$
|
(15.42
|
)
|
|
$
|
(4.85
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations
|
|
$
|
0.92
|
|
|
$
|
0.93
|
|
|
$
|
5.37
|
|
|
$
|
(14.19
|
)
|
|
$
|
(6.86
|
)
|
Earnings (loss) from discontinued operations
|
|
|
0.74
|
|
|
|
1.95
|
|
|
|
0.51
|
|
|
|
(1.23
|
)
|
|
|
2.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
$
|
1.66
|
|
|
$
|
2.88
|
|
|
$
|
5.88
|
|
|
$
|
(15.42
|
)
|
|
$
|
(4.85
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
138
DEVON
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Earnings
(Loss) from Continuing Operations
The first quarter of 2009 includes a reduction of the carrying
values of United States oil and gas properties totaling
$6.4 billion ($4.1 billion after income taxes, or
$9.20 per diluted share).
The fourth quarter of 2009 includes restructuring costs that
relate to Devons planned asset divestitures and total
$105 million ($67 million after income taxes, or $0.15
per diluted share).
The first and second quarters of 2008 include unrealized losses
on Devons 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 the 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 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 fourth quarter of 2008 includes reductions of the carrying
values of United States and Canadian oil and gas properties
totaling $9.9 billion ($6.7 billion after income
taxes, or $15.06 per diluted share).
Earnings
(Loss) from Discontinued Operations
The first quarter of 2009 includes reductions of the carrying
values of oil and gas properties totaling $108 million
($105 million after income taxes, or $0.24 per diluted
share).
The fourth quarter of 2009 includes restructuring costs that
relate to Devons planned asset divestitures and total
$48 million ($31 million after income taxes, or $0.07
per diluted share).
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 fourth quarter of 2008 includes reductions of the carrying
values of oil and gas properties totaling $494 million
($465 million after income taxes, or $1.05 per diluted
share).
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, 2009 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 18, 2010, management concluded that its internal
control over financial reporting was effective as of
December 31, 2009.
The effectiveness of Devons internal control over
financial reporting as of December 31, 2009 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, 2009, 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 2009 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, 2010.
|
|
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, 2010.
|
|
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, 2010.
|
|
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, 2010.
|
|
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, 2010.
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 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 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
filing, filed 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 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).
|
|
3
|
.1
|
|
Registrants Restated Certificate of Incorporation
(incorporated by reference to Exhibit 3.1 of
Registrants
Form 10-K
filed on March 7, 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 3.1 of Registrants
Form 8-K
filed on March 6, 2009).
|
|
4
|
.1
|
|
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 April 9, 2002).
|
|
4
|
.2
|
|
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).
|
142
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
4
|
.3
|
|
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
|
.4
|
|
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 October 31, 2001).
|
|
4
|
.5
|
|
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 with the SEC 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 with the SEC on September 28, 2001).
|
|
4
|
.6
|
|
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
for the year ended December 31, 2005).
|
|
4
|
.7
|
|
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)).
|
|
4
|
.8
|
|
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
|
.9
|
|
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 with the SEC on May 14, 2001).
|
|
4
|
.10
|
|
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
for the year ended December 31, 2005).
|
|
4
|
.11
|
|
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
|
.12
|
|
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).
|
143
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
4
|
.13
|
|
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
|
.14
|
|
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
for the year ended December 31, 2005).
|
|
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
as filed 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 February 27, 2009).
|
|
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).
|
|
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 February 27, 2009).
|
|
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).
|
144
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
10
|
.9
|
|
364-Day
Credit Agreement dated as of November 3, 2009 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 5, 2009).
|
|
10
|
.10
|
|
Devon Energy Corporation 2009 Long-Term Incentive Plan
(incorporated by reference to Registrants
Form S-8
Registration
No. 333-159796,
filed June 5, 2009).*
|
|
10
|
.11
|
|
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
|
.12
|
|
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
|
.13
|
|
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
|
.14
|
|
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
|
.15
|
|
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
|
.16
|
|
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).*
|
|
10
|
.17
|
|
Amended and Restated Form of Employment Agreement between
Registrant and David A. Hager, 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
(incorporated by reference to Exhibit 10.19 to
Registrants
Form 10-K
filed February 27, 2009).*
|
|
10
|
.18
|
|
Form of Employee Nonqualified Stock Option Award Agreement under
the 2009 Long-Term Incentive Plan between Registrant and David
A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank
W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F.
Whitsitt for nonqualified stock options granted.*
|
|
10
|
.19
|
|
Form of Incentive Stock Option Award Agreement under the 2009
Long-Term Incentive Plan between Registrant and David A. Hager,
R. Alan Marcum, J. Larry Nichols, John Richels, Frank W.
Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F.
Whitsitt for incentive stock options granted.*
|
|
10
|
.20
|
|
Form of Non-Management Director Nonqualified Stock Option Award
Agreement under the Devon Energy Corporation 2009 Long-Term
Incentive Plan between Registrant and all Non-Management
Directors for nonqualified stock options granted.*
|
|
10
|
.21
|
|
Form of Restricted Stock Award Agreement under the 2009
Long-Term Incentive Plan between Registrant and David A. Hager,
R. Alan Marcum, J. Larry Nichols, John Richels, Frank W.
Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F.
Whitsitt for restricted stock awards.*
|
|
10
|
.22
|
|
Form of Restricted Stock Award Agreement under the 2009
Long-Term Incentive Plan between Registrant and all
Non-Management Directors for restricted stock awards.*
|
|
10
|
.23
|
|
Amended and Restated Severance Agreement between Registrant and
Danny J. Heatly, dated December 15, 2008 (incorporated by
reference to Exhibit 10.27 to Registrants
Form 10-K
filed on February 27, 2009).*
|
|
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.
|
145
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
23
|
.4
|
|
Consent of AJM Petroleum Consultants.
|
|
31
|
.1
|
|
Certification of principal executive office pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2
|
|
Certification of principal financial officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1
|
|
Certification of principal executive officer 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 principal financial officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
99
|
.1
|
|
Report of LaRoche Petroleum Consultants.
|
|
99
|
.2
|
|
Report of Ryder Scott Company, L.P.
|
|
99
|
.3
|
|
Report of AJM Petroleum Consultants.
|
|
101
|
.INS
|
|
XBRL Instance Document
|
|
101
|
.SCH
|
|
XBRL Taxonomy Extension Schema Document
|
|
101
|
.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
101
|
.LAB
|
|
XBRL Taxonomy Extension Labels Linkbase Document
|
|
101
|
.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
101
|
.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
|
|
|
* |
|
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 24, 2010
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 24, 2010
|
|
|
|
|
|
/s/ John
Richels
John
Richels
|
|
President and Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ Danny
J. Heatly
Danny
J. Heatly
|
|
Senior Vice President Accounting and Chief
Accounting Officer
|
|
February 24, 2010
|
|
|
|
|
|
/s/ Thomas
F. Ferguson
Thomas
F. Ferguson
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ John
A. Hill
John
A. Hill
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ Robert
L. Howard
Robert
L. Howard
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ Michael
M. Kanovsky
Michael
M. Kanovsky
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ J.
Todd Mitchell
J.
Todd Mitchell
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ Robert
A. Mosbacher, Jr.
Robert
A. Mosbacher, Jr.
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ Mary
P. Ricciardello
Mary
P. Ricciardello
|
|
Director
|
|
February 24, 2010
|
147
INDEX TO
EXHIBITS
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
10
|
.18
|
|
Form of Employee Nonqualified Stock Option Award Agreement under
the 2009 Long-Term Incentive Plan between Registrant and David
A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank
W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F.
Whitsitt for nonqualified stock options granted.*
|
|
10
|
.19
|
|
Form of Incentive Stock Option Award Agreement under the 2009
Long-Term Incentive Plan between Registrant and David A. Hager,
R. Alan Marcum, J. Larry Nichols, John Richels, Frank W.
Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F.
Whitsitt for incentive stock options granted.*
|
|
10
|
.20
|
|
Form of Non-Management Director Nonqualified Stock Option Award
Agreement under the Devon Energy Corporation 2009 Long-Term
Incentive Plan between Registrant and all Non-Management
Directors for nonqualified stock options granted.*
|
|
10
|
.21
|
|
Form of Restricted Stock Award Agreement under the 2009
Long-Term Incentive Plan between Registrant and David A. Hager,
R. Alan Marcum, J. Larry Nichols, John Richels, Frank W.
Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F.
Whitsitt for restricted stock awards.*
|
|
10
|
.22
|
|
Form of Restricted Stock Award Agreement under the 2009
Long-Term Incentive Plan between Registrant and all
Non-Management Directors for restricted stock awards.*
|
|
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 principal executive office pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2
|
|
Certification of principal financial officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1
|
|
Certification of principal executive officer 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 principal financial officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
99
|
.1
|
|
Report of LaRoche Petroleum Consultants.
|
|
99
|
.2
|
|
Report of Ryder Scott Company, L.P.
|
|
99
|
.3
|
|
Report of AJM Petroleum Consultants.
|
|
101
|
.INS
|
|
XBRL Instance Document
|
|
101
|
.SCH
|
|
XBRL Taxonomy Extension Schema Document
|
|
101
|
.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
101
|
.LAB
|
|
XBRL Taxonomy Extension Labels Linkbase Document
|
|
101
|
.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
101
|
.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
|
|
|
* |
|
Compensatory plans or arrangements |