e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
FORM 10-K
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(Mark One)
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þ
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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,
2010
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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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For the transition period
from to
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Commission file number 1-4300
APACHE CORPORATION
(Exact name of registrant as
specified in its charter)
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Delaware
(State or other jurisdiction of
incorporation or organization)
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41-0747868
(I.R.S. Employer Identification
No.)
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One Post Oak Central, 2000 Post Oak Boulevard,
Suite 100, Houston, Texas 77056-4400
(Address of principal executive offices)
Registrants telephone number, including area code
(713) 296-6000
Securities registered pursuant to Section 12(b) of the
Act:
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Name of Each Exchange
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Title of Each Class
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On Which Registered
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Common Stock, $0.625 par value
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New York Stock Exchange,
Chicago Stock Exchange and
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NASDAQ National Market
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Preferred Stock Purchase Rights
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New York Stock Exchange and
Chicago Stock Exchange
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Apache Finance Canada Corporation
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New York Stock Exchange
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7.75% Notes Due 2029
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Irrevocably and Unconditionally
Guaranteed by Apache Corporation
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Depositary Shares Representing a 1/20th
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Interest in a Share of 6.00% Mandatory
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New York Stock Exchange
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Convertible Preferred Stock, Series D
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Securities registered pursuant to Section 12(g) of the
Act: Common Stock, $0.625 par value
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 Website, 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
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
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Large
accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting
company o
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(Do not check if a smaller reporting company)
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
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Aggregate market value of the voting and non-voting common
equity held by non-affiliates of registrant as of June 30,
2010
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$
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28,439,311,280
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Number of shares of registrants common stock outstanding
as of January 31, 2011
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382,752,217
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DOCUMENTS
INCORPORATED BY REFERENCE
Portions of registrants proxy statement relating to
registrants 2011 annual meeting of stockholders have been
incorporated by reference in Part II and Part III of
this annual report on
Form 10-K.
TABLE OF
CONTENTS
DESCRIPTION
i
DEFINITIONS
All defined terms under
Rule 4-10(a)
of
Regulation S-X
shall have their statutorily prescribed meanings when used in
this report. As used in this document:
3-D
means three-dimensional.
4-D
means four-dimensional.
b/d means barrels of oil or natural gas liquids per
day.
bbl or bbls means barrel or barrels of
oil.
bcf means billion cubic feet.
boe means barrel of oil equivalent, determined by
using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
boe/d means boe per day.
Btu means a British thermal unit, a measure of
heating value, which is approximately equal to one Mcf.
LIBOR means London Interbank Offered Rate.
LNG means liquefied natural gas.
Mb/d means Mbbls per day.
Mbbls means thousand barrels of oil.
Mboe means thousand boe.
Mboe/d means Mboe per day.
Mcf means thousand cubic feet of natural gas.
Mcf/d means Mcf per day.
MMbbls means million barrels of oil.
MMboe means million boe.
MMBtu means million Btu.
MMBtu/d means MMBtu per day.
MMcf means million cubic feet of natural gas.
MMcf/d
means MMcf per day.
NGL or NGLs means natural gas liquids,
which are expressed in barrels.
NYMEX means New York Mercantile Exchange.
Oil includes crude oil and condensate.
PUD means proved undeveloped.
SEC means United States Securities and Exchange
Commission.
Tcf means trillion cubic feet.
U.K. means United Kingdom.
U.S. means United States.
With respect to information relating to our working interest in
wells or acreage, net oil and gas wells or acreage
is determined by multiplying gross wells or acreage by our
working interest therein. Unless otherwise specified, all
references to wells and acres are gross.
ii
PART I
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ITEMS 1
AND 2.
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BUSINESS
AND PROPERTIES
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This Annual Report on
Form 10-K
and the documents incorporated herein by reference contain
forward-looking statements based on expectations, estimates, and
projections as of the date of this filing. These statements by
their nature are subject to risks, uncertainties, and
assumptions and are influenced by various factors. As a
consequence, actual results may differ materially from those
expressed in the forward-looking statements. See Part II,
Item 7A Forward-Looking Statements and Risk of
this
Form 10-K.
General
Apache Corporation, a Delaware corporation formed in 1954, is an
independent energy company that explores for, develops and
produces natural gas, crude oil and natural gas liquids. We
currently have exploration and production interests in seven
countries: the U.S., Canada, Egypt, Australia, offshore the
United Kingdom in the North Sea, Argentina, and Chile.
Our common stock, par value $0.625 per share, has been listed on
the New York Stock Exchange (NYSE) since 1969, on the Chicago
Stock Exchange (CHX) since 1960, and on the NASDAQ National
Market (NASDAQ) since 2004. On May 25, 2010, we filed
certifications of our compliance with the listing standards of
the NYSE and the NASDAQ, including our principal executive
officers certification of compliance with the NYSE
standards. Through our website, www.apachecorp.com, you can
access, free of charge, electronic copies of the charters of the
committees of our Board of Directors, other documents related to
Apaches corporate governance (including our Code of
Business Conduct and Governance Principles) and documents Apache
files with 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 filed or furnished
pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934. Included in our annual and quarterly
reports are the certifications of our principal executive
officer and our principal financial officer that are required by
applicable laws and regulations. Access to these electronic
filings is available as soon as reasonably practicable after we
file such material with, or furnish it to, the SEC. You may also
request printed copies of our committee charters or other
governance documents free of charge by writing to our corporate
secretary at the address on the cover of this report. Our
reports filed with the SEC are also made available to read and
copy at the SECs Public Reference Room at
100 F Street, N.E., Washington, D.C., 20549. You
may obtain information about the Public Reference Room by
contacting the SEC at
1-800-SEC-0330.
Reports filed with the SEC are also made available on its
website at www.sec.gov. From time to time, we also post
announcements, updates and investor information on our website
in addition to copies of all recent press releases.
We hold interests in many of our U.S., Canadian and other
international properties through subsidiaries. Properties to
which we refer in this document may be held by those
subsidiaries. We treat all operations as one line of business.
References to Apache or the Company
include Apache Corporation and its consolidated subsidiaries
unless otherwise specifically stated.
Growth
Strategy
Apaches mission is to grow a profitable global exploration
and production company in a safe and environmentally responsible
manner for the long-term benefit of our stockholders.
Apaches long-term perspective has many dimensions, with
the following core strategic components:
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balanced portfolio of core assets;
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conservative capital structure; and
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rate of return focus.
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Throughout the cycles of our industry, these strategies have
underpinned our ability to deliver long-term production and
reserve growth and achieve competitive investment rates of
return for the benefit of our shareholders. We have increased
reserves 22 out of the last 25 years and production 30 out
of the past 32 years, a testament to our consistency over
the long-term.
1
Apache pursues opportunities for growth through exploration and
development drilling, supplemented by occasional strategic
acquisitions. In the years immediately prior to 2010, we were
relatively absent from the acquisition market. We believed the
market was overheated as oil and gas prices spiked, and the
opportunities we identified did not meet our criteria for risk,
reward, rate of return
and/or
growth potential. We built our cash position while drilling from
our existing inventory of prospects and waiting for the right
transactions to add to our portfolio. During 2010 we completed
more than $11 billion in acquisitions and made significant
progress with exploitation on existing core properties.
The current-year acquisitions fit well with our long-term
strategy of maintaining a balanced portfolio of core assets.
They included high-quality assets with a diversity of geologic
and geographic risk, product mix and reserve life. The
properties are strategically positioned with our existing
infrastructure and play to the strengths that come with our
experience operating in the Permian Basin, Canada and Gulf of
Mexico (GOM). The Mariner merger also provided a strategic
position in the deepwater GOM, which is relatively under
explored and oil prone and gives Apache exposure to significant
domestic oil reserves. The transactions drove a 42 percent,
or 10 million acre,
year-over-year
increase in our undeveloped gross acres, adding to our inventory
of future drilling and exploration opportunities.
2010
Acquisitions
North
America
Shelf acquisition On June 9, 2010, Apache
completed the acquisition of oil and gas assets in the Gulf of
Mexico shelf from Devon Energy Corporation for
$1.05 billion.
Mariner merger On November 10, 2010,
Apache completed the acquisition of Mariner Energy, Inc. for
stock and cash consideration totaling $2.7 billion. We also
assumed approximately $1.7 billion of Mariners debt
with the merger.
Permian acquisition On August 10, 2010,
we completed the acquisition of BP plcs (BP) oil and gas
operations, acreage and infrastructure in the Permian Basin for
$2.5 billion, net of preferential rights to purchase.
Canadian acquisition On October 8, 2010,
we completed the acquisition of substantially all of BPs
upstream natural gas business in western Alberta and British
Columbia for $3.25 billion.
International
Egyptian acquisition On November 4, 2010,
we completed the acquisition of BPs assets in Egypts
Western Desert for $650 million.
Balanced
Portfolio of Core Assets
A cornerstone of our long-term strategy is balancing our
portfolio of assets through diversity of geologic risk,
geographic risk, hydrocarbon mix (crude oil versus natural gas),
and reserve life in order to achieve consistency in results. Our
portfolio of geographic locations provides variation of all of
these factors. We have exploration and production operations in
seven countries, spanning five continents: the Gulf Coast,
Permian and Central regions of the U.S., Canada, Egypt, the U.K.
North Sea, Australia, Argentina and on the Chilean side of the
island of Tierra del Fuego. Our 2010 acquisitions added to our
asset base in the United States, Canada, and Egypt.
In addition, each of our producing regions has achieved an
economy of scale providing a vehicle for cost-effective base
production and a combination of lower- and medium-risk drilling
opportunities. The net cash provided by operating activities
(cash flows) generated by our current production base funds our
drilling and development capital program, giving us the ability
to pursue new exploration targets over our 35 million gross
undeveloped acres across the globe and develop our pipeline of
exploration discoveries. Those developments will fund the next
round of exploration activities and development programs.
In 2010:
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No single region contributed more than 28 percent of our
equivalent production or revenue.
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No single region held more than 26 percent of our year-end
estimated proved reserves.
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The mixture of reserve life (estimated reserves divided by
annual production) in our countries, which translates into
balance in the timing of returns on our investments, ranges from
as short as five years to as long as 25 years.
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Our balanced product mix provides a measure of protection
against price deterioration in a given product while retaining
upside potential through a significant increase in either
commodity price. In 2010 crude oil and liquids provided
52 percent of our production and 77 percent of our
revenue.
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At year-end our estimated proved reserves were 44 percent
crude oil and liquids and 56 percent natural gas.
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Our international gas portfolio, which accounted for
19 percent of our 2010 worldwide equivalent production,
positions us to take advantage of increasing prices in Argentina
and Australia.
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Conservative
Capital Structure
Maintaining a strong balance sheet and financial flexibility is
a core strategic component of our long-term strategy. We believe
our balance sheet, and the financial flexibility it provides, is
one of our most important strategic assets. Maintaining a strong
balance sheet underpins our ability to weather commodity price
volatility and has enabled us to deliver
long-term
production and reserves growth throughout the cycles of our
industry. It is also key in positioning us to pursue
value-creating acquisitions when opportunities arise, as they
did in 2010.
We exited 2010 with a
debt-to-capitalization
ratio of 25 percent, an increase of only one percent
despite current year capital investments of $17 billion,
and $2.4 billion of available committed borrowing capacity.
Rate
of Return Focus
Another core component to our long-term strategy is focusing on
rate-of-return.
We do so through centralized management and incentive systems,
decentralized decision making, strict cost control, and the
creative application of technology.
Our centralized management and incentive systems provide a
uniform process of measuring success across Apache. They
incentivize high
rate-of-return
activities but allow for appropriate risk-taking to drive future
growth. Results of operations and rates of return on invested
capital are measured monthly, reviewed with management
quarterly, and utilized to determine annual performance awards.
We review capital allocations, at least quarterly, utilizing
estimates of internally-generated cash flow. We do this through
a disciplined and focused process that includes analyzing
current economic conditions, projected rates of return on
internally-generated drilling prospects, opportunities for
tactical acquisitions, land positions with additional drilling
prospects or, occasionally, new core areas that could enhance
our portfolio.
We also use technology to reduce risk, decrease time and costs
and maximize recoveries from reservoirs. Apache scientists and
engineers have been granted numerous patents for a range of
inventions, from systems used for interpreting seismic data and
processing well logs to improvements in drilling and completion
techniques.
One such example is a manifold developed for our Horn River
Shale gas play in northeast British Columbia, where Apache is
employing pad-drilling technology. Apache engineers developed
and applied for a patent on a manifold that can connect all
horizontal wells on a single pad, driving down costs by reducing
non-productive time on our
24-hour-a-day
hydraulic fracturing operations. This technology will reduce
costs and increase Apaches rate of return on potentially
thousands of future wells across our leasehold.
At our Forties field in the North Sea, Apache is using
techniques that bring together many sources of data to give an
accurate view of the current state of the field and identify
likely places to find unswept oil deposits. Four-dimensional
modeling, which uses reservoir engineering data and a series of
3-D seismic
surveys, is utilized by Apache to create a time-lapse picture
that shows where oil remains after more than 35 years of
production. The latest model of the reservoir highlights the
potential for stranded oil accumulations and enhances the
success of the ongoing drilling program as well as identifies
new potential drilling locations.
For a more in-depth discussion of our 2010 results and the
Companys capital resources and liquidity, please see
Part II, Item 7 Managements
Discussion and Analysis of Financial Condition and Results of
Operations of this
Form 10-K.
3
Geographic
Area Overviews
We currently have exploration and production interests in seven
countries: the U.S., Canada, Egypt, Australia, offshore the
United Kingdom in the North Sea, Argentina, and Chile.
The following table sets out a brief comparative summary of
certain key 2010 data for each of our operating areas.
Additional data and discussion is provided in Part II,
Item 7 of this
Form 10-K.
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Percentage
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2010
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2010 Gross
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Percentage
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12/31/10
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of Total
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Gross
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New
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of Total
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2010
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Estimated
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Estimated
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New
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Productive
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2010
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2010
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Production
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Proved
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Proved
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Wells
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Wells
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Production
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Production
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Revenue
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Reserves
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Reserves
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Drilled
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Drilled
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(In MMboe)
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(In millions)
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(In MMboe)
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United States
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84.7
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35
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%
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$
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4,300
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1,304
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44
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%
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410
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388
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Canada
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30.5
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13
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1,074
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757
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26
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182
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173
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Total North America
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115.2
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48
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5,374
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2,061
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70
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592
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561
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Egypt
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59.0
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24
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3,372
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307
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10
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204
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177
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Australia
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28.9
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12
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1,459
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314
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11
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31
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23
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North Sea
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20.9
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9
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1,606
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155
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5
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20
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12
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Argentina
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16.0
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7
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372
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116
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4
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56
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52
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Other International
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1
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1
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Total International
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124.8
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52
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6,809
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892
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30
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312
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265
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Total
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240.0
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100
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%
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$
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12,183
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2,953
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100
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%
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904
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826
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North
America
Apaches North American asset base comprises the Gulf
Coast, Permian and Central regions of the U.S. and its
operations in Canada. In 2010 our North America assets
contributed 48 percent of our production and
44 percent of our oil and gas production revenues. At
year-end 70 percent of our estimated proved reserves were
located in North America.
United
States
Overview We have 9.7 million gross acres
across the U.S., approximately half of which is undeveloped.
Approximately 30 percent of the undeveloped acreage is
held-by-production.
Our U.S. assets are located in the Gulf Coast, Permian and
Central regions. The three regions provide our U.S. asset
base with a balance of hydrocarbon mix and reserve life. In 2010
48 percent of our U.S. production and 58 percent
of our U.S. year-end reserves were oil and liquids. In
addition, the reserve life of our U.S. regions ranged from
nine to 30 years with the Gulf Coast regions
shorter-lived reserves balancing longer-lived reserves in the
Central and Permian regions. In 2010 35 percent of
Apaches equivalent production and 44 percent of
Apaches total year-end reserves were in the U.S.
Gulf Coast Region Our Gulf Coast assets are
primarily located in and along the Gulf of Mexico, in the areas
on- and offshore Texas and Louisiana. In 2010 the Gulf Coast
region contributed approximately 19 percent of our
worldwide production and revenues, predominately from offshore
properties. Apaches Gulf Coast operations grew
significantly during the year with the June acquisition of
Devons Gulf of Mexico shelf properties and the addition of
properties with the Mariner merger in November 2010. These
transactions were aligned with our long-term core strategy of
maintaining a balanced portfolio of assets. The region accounted
for nearly 13 percent of our estimated proved reserves at
year-end compared to 13 percent the previous year.
Apache has been the largest offshore
held-by-production
acreage owner since 2004 and is now the largest producer in
waters less than 500 feet deep (shelf). The Devon
acquisition and Mariner merger brought significant development
and exploration opportunities with high-quality assets
complementary to our existing assets, as well as a strategic
presence in the deepwater Gulf of Mexico (waters greater than
500 feet deep). The deepwater Gulf of Mexico is relatively
underexplored and oil prone and provides exposure to significant
reserve and production
4
potential. Acreage increased 76 percent to 5.3 million gross
acres: 2.5 million deepwater, 1.4 million shelf, and 1.4 million
onshore. Over 50 percent of the regions acreage was
undeveloped.
In 2010 the Bureau of Ocean Energy Management, Regulation and
Enforcement (BOEMRE) announced a series of moratoria, which
directed oil and gas lessees and operators to cease drilling new
deepwater (depths greater than 500 feet) wells on the Outer
Continental Shelf (OCS), and put oil and gas lessees and
operators on notice that, with certain exceptions, the BOEMRE
would not consider drilling permits for deepwater wells and
related activities. While the moratoria have been formally
lifted, no new permits for deepwater drilling have been issued
as of the date of this filing.
In addition, the BOEMRE issued new regulations in 2010 requiring
additional information, documentation and analysis for all new
wells on the OCS. The effect of these new regulations was to
significantly slow down issuance of permits for shallow wells.
Apache continues to operate under these new regulations and,
through February 2011, has received 25 drilling permits for
shallow wells. Current permitting activity has been slowed
compared to prior-year levels, and the Company has budgeted its
exploration and development activity accordingly.
Despite the curtailment of activity in the region stemming from
new regulations, the region had a productive year, drilling or
participating in 63 wells (36 in the Gulf of Mexico), up
from 26 wells (20 in the Gulf of Mexico) in 2009, and
performing 365 workovers and recompletions.
As a result of 2010 acquisitions and the differing growth and
opportunity profiles, we have divided the assets into three
regions beginning in 2011: Gulf of Mexico shelf, Gulf of Mexico
deepwater and Gulf Coast onshore. In 2011 the Company plans to
invest approximately $200 million, $1 billion and
$500 million in the Gulf Coast onshore, Gulf of Mexico
shelf and Gulf of Mexico deepwater assets, respectively, subject
to receipt of permits from BOEMRE. The capital will be spent on
drilling, recompletion and development projects, equipment
upgrades, production enhancement projects, lease acquisition,
seismic acquisition and abandonment activities.
On September 16, 2010, the BOEMRE and the Department of the
Interior issued a Notice to Lessees and Operators (NTL) updating
the procedures and timing for decommissioning offshore wells and
platforms. While the so called Idle Iron NTL may
result in an acceleration of timing to abandon certain wells and
remove certain platforms in the Gulf of Mexico, our ongoing
active well and equipment abandonment program mitigated the
impact of the new regulations on Apache. The Company spent
approximately $260 million to plug offshore wells and
remove platforms in 2010. With the addition of the Devon and
Mariner offshore properties, we currently plan to spend
approximately $350 million in 2011.
Central Region The Central region includes
nearly 2,000 wells and controls over one million gross
acres primarily in western Oklahoma, the Texas panhandle and
east Texas. Most of the regions acreage is
held-by-production.
Although the reserves and production are primarily natural gas,
given the price disparity between oil and gas, the region
successfully targeted oil and liquids rich gas plays in 2010.
Oil-and liquids-production increased by 54 percent and
90 percent, respectively, over the prior year. In 2010
Apache drilled or participated in the drilling of 84 wells,
99 percent of which were completed as producers. The region
also performed 144 workovers and recompletions. The
regions year-end estimated proved reserves, which were
90 percent natural gas, were six percent of Apaches
total.
In the Anadarko basin, the Granite Wash play has long been a
core stacked-pay target for the region, where we have drilled
many vertical wells over the past several decades. As a result,
we control approximately 200,000 gross acres in this
liquid-rich play, mostly
held-by-production.
Despite the numerous vertical wells drilled, the Granite Wash is
re-emerging as a horizontal play that is capitalizing on
advances in horizontal drilling and fracturing technology and
high oil prices given the rich liquids yield of the wells. In
2009 we drilled our first operated horizontal well in the
Granite Wash. In 2010 we ramped up activity to 10 rigs, drilling
31 horizontal Granite Wash wells and testing six additional
horizons including the Hogshooter interval, which is shallower,
younger and oilier than previously tested Granite Wash targets.
We have completed two wells in the Hogshooter interval, which
are separated by over fifteen miles of what appears to be very
prolific acreage, primarily owned and operated by Apache. We
have identified hundreds of additional Granite Wash horizontal
well locations across our acreage. In 2011 we plan to keep a
minimum of eight rigs running in this play and drill in excess
of 40 horizontal wells, targeting several horizons.
5
We have had success on the Anadarko shelf drilling relatively
shallow horizontal wells into the Cherokee formation. In 2010 we
completed four horizontal wells in the Cherokee play with
vertical depths of 6,500 feet and horizontal penetrations
of nearly one mile. These wells had average
30-day rates
of 520 b/d and 850 Mcf/d and an average Apache working
interest of 78 percent. The wells are currently
producing an average of 150 b/d and 560 Mcf/d. We plan to
drill 13 horizontal wells in the Cherokee in 2011. In addition,
we have had success with our program targeting oil in Ochiltree
County, Texas. During the year we drilled four wells in the
Cleveland formation at a vertical depth of 7,500 feet and
participated in one horizontal well in the Marmaton formation at
a depth of 11,000 feet. Two of the Cleveland wells and the
Marmaton well commenced production in late 2010 at an average
initial rate of approximately 500 b/d. Apaches average
working interest in the five wells is 90 percent. The two
remaining Cleveland wells are awaiting completion, and we intend
to keep at least one drilling rig running in the area throughout
the year.
We are also employing horizontal drilling and multistage
fracture technology in east Texas. In 2010 we drilled seven
horizontal Bossier wells in Freestone County, Texas, where we
own 45,000 gross acres. The wells produced an aggregate
7.34 Bcf during the year and are currently producing
37 MMcf/d,
33 MMcf/d
net to Apache.
In 2011 the Central region plans to invest approximately
$430 million in drilling, recompletions, equipment
upgrades, production enhancement projects and lease
acquisitions, primarily in the Anadarko basin. We currently plan
to keep 12 rigs running all year, with more than 95 percent
of the wells drilled horizontally and 89 percent of the
wells drilled targeting oil or high liquid yield gas.
Permian Region Our Permian region, carved out
of our Central region, grew significantly in 2010. In July we
opened a new regional office in Midland. The regions
property and acreage base increased substantially upon
completion of the BP acquisition in July and the Mariner merger
in November. These two transactions combined added approximately
35 Mboe/d of new production and more than doubled our acreage to
over three million gross acres with exposure to every known play
in the Permian Basin. The drilling rig count has increased from
five operating at the beginning of 2010 to more than 20 at the
end of the year. The workover and completion rig count has
increased from 56 to 80, and the employee headcount in Midland
and the field has increased by more than 200 during this same
time period. The region drilled or participated in
263 wells and completed approximately 1,100 workovers and
recompletions in 2010.
Apache is one of the largest operators in the Permian Basin,
operating more than 11,000 wells in 152 fields, including
45 waterfloods and six
CO2
floods. Fourth-quarter net production was 59 Mb/d and
162 MMcf/d
and included only six weeks of production from the properties
acquired in the Mariner merger. The Permian regions
year-end estimated proved reserves, which were 76 percent
oil and liquids, were 25 percent of Apaches total.
During 2010 the Permian region tested horizontal drilling
opportunities in four mature waterflood fields, the North
McElroy, Shafter Lake, TXL South, and Dean Units, all of which
resulted in commercial successes. The region ultimately drilled
and completed a total of 17 horizontal wells in the units. The
Midland team has developed a significant inventory of potential
horizontal drilling applications on existing Apache acreage
across the Permian Basin. In 2011 we plan to drill 41 horizontal
wells across a number of the regions assets.
In 2010 the region signed a
20-year
CO2
supply contract to develop approximately 8.4 MMboe of
estimated proved reserves at Roberts Unit. Our 2010 drilling
results at Roberts Unit include 15 production and
CO2
injection wells that resulted in higher than predicted
production rates. The
CO2
development at Roberts Unit will continue during 2011 with 43
new production and injection wells planned.
In 2011 the Permian Region plans to invest approximately
$930 million in drilling, recompletion projects, equipment
upgrades, expansion of existing facilities and equipment and
leasing new acreage. We plan to keep more than 20 rigs running
all year drilling an estimated 368 wells. The regions
2011 drilling activity will focus on a combination of Apache
legacy assets and the newly acquired Mariner and BP properties.
On the BP properties alone, the region has identified more than
2,000 drilling locations. Current plans include 130 wells
in the Deadwood area (acquired from Mariner) where we hold
63,000 net acres subject to continuous drilling clauses and
in the Empire Yeso area (acquired from BP), where we plan to
drill approximately 55 wells.
U.S. Marketing In general, most of our
U.S. gas is sold at either monthly or daily market prices.
Our natural gas is sold primarily to Local Distribution
Companies (LDCs), utilities, end-users and integrated major oil
companies.
6
Apache primarily markets its U.S. crude oil to integrated
major oil companies, marketing and transportation companies and
refiners. The objective is to maximize the value of crude oil
sold by identifying the best markets and most economical
transportation routes available to move the product. Sales
contracts are generally
30-day
evergreen contracts that renew automatically until canceled by
either party. These contracts provide for sales that are priced
daily at prevailing market prices.
Canada
Overview Apache has 6.3 million net acres
across the provinces of British Columbia, Alberta and
Saskatchewan, including approximately 1.3 million net
mineral and leasehold acres in Western Alberta and British
Columbia acquired from BP in 2010. Our acreage base provides a
significant inventory of both low-risk development drilling
opportunities in and around a number of Apache fields and
higher-risk, higher-reward exploration opportunities. At
year-end 2010 our Canadian region held approximately
26 percent of our estimated proved reserves. In 2010 we
drilled or participated in 182 wells in Canada, eight of
which were exploratory wells. The regions 2010 natural gas
production increased ten percent, while liquids production was
one percent higher.
On our conventional assets, we are focused on oil projects
located primarily in Alberta and Saskatchewan, enabling us to
take advantage of the current strong oil prices. We will utilize
our drilling technology and reservoir modeling expertise to
identify and exploit unswept oil in our waterflood projects in
the House Mountain, Leduc and Snipe Lake fields. Additional
drilling for oil will continue on our enhanced oil recovery
projects in Midale and Provost with long-term plans to develop
and expand waterfloods and
CO2
projects. We will also continue intermediate-depth gas
development drilling in Kaybob and West 5 areas.
Apaches near-term natural gas production growth will
likely be driven by our activity in two large growth plays in
British Colombia: shale gas in the Horn River basin and tight
sands in the Noel area. In the Horn River basin, Apache has a
50-percent interest and 210,000 net acres. During 2010
Apache reached a peak of
100 MMcf/d
net, drilled 29 new wells and completed 30 wells. In 2011
we plan to drill 10 and complete 28 wells in the Horn River
basin. Apache acquired its 100-percent working interest in the
Noel area from BP in October 2010. Gas production from Noel
reached an exit rate of
100 MMcf/d
in December 2010. In 2011 we are currently planning a horizontal
drilling program of approximately 11 wells in the Noel
Area. Apache has identified many years of drilling activity in
both plays.
During the first quarter of 2010 Apache Canada Ltd. (Apache
Canada), through its subsidiaries, purchased a 51 percent
interest in a planned LNG export terminal (Kitimat LNG facility)
and a 25.5-percent interest in a partnership that owns a related
proposed pipeline. In the second quarter of 2010 EOG Resources
Canada, Inc. (EOG Canada), through its wholly-owned
subsidiaries, acquired the remaining 49 percent of the
Kitimat LNG facility and a 24.5-percent interest in the pipeline
partnership. In February 2011 Apache Canada and EOG Canada
entered into an agreement to purchase the remaining 50-percent
interest in the pipeline partnership from Pacific Northern Gas
Ltd. (PNG). Under the terms of the agreement, PNG will operate
and maintain the planned pipeline under a seven-year agreement
with Apache Canada and EOG Canada with provisions for five-year
renewals. It also includes a
20-year
transportation service arrangement which may require Apache
Canada and EOG Canada, under certain circumstances, to use a
portion of PNGs current pipeline capacity. Upon close of
the transaction, expected in the second quarter of 2011, Apache
Canada and EOG Canada will own 51 percent and
49 percent, respectively, of the pipeline partnership and
proposed pipeline.
Apache Canada and EOG Canada plan to build the Kitimat LNG
facility on Bish Cove near the Port of Kitimat, 400 miles
north of Vancouver, British Columbia. The facility is planned
for an initial minimum capacity of
700 MMcf/d,
or five million metric tons of LNG per year, of which Apache
Canada has reserved 51 percent. The proposed
287-mile
pipeline will originate in Summit Lake, British Columbia, and is
designed to link the Kitimat LNG facility to the pipeline system
currently servicing western Canadas natural gas producing
regions. Apache Canada will have rights to 51-percent of the
capacity in the proposed pipeline. Completion of the front-end
engineering and design (FEED) study and a final investment
decision are targeted for late 2011. Construction is expected to
commence in 2012, with commercial operations projected to begin
in 2015.
Our plans for 2011 are to drill or participate in a total of
149 wells in Canada, including 129 development wells and 20
exploratory wells. The planned development includes nine drills
and 28 completions in the Horn River basin.
7
During 2011 the region plans to invest approximately
$800 million for drilling and development projects,
equipment upgrades, production enhancement projects and seismic
acquisition. Approximately $25 million is allocated for
Gathering, Transmission and Processing (GTP) assets.
Marketing Our Canadian natural gas marketing
activities focus on sales to LDCs, utilities, end-users,
integrated major oil companies, supply aggregators and
marketers. We maintain a diverse client portfolio, which is
intended to reduce the concentration of credit risk in our
portfolio. To diversify our market exposure, we transport
natural gas via our firm transportation contracts to California,
the Chicago area and eastern Canada. We sell the majority of our
Canadian gas on a monthly basis at either
first-of-the-month
or daily prices. In 2010 approximately two percent of our gas
sales were subject to long-term fixed-price contracts, with the
latest expiration in 2011.
Our Canadian crude is sold primarily to integrated major oil
companies and marketers. We sell our oil based on West Texas
Intermediate (WTI) and sell our NGLs based on postings or a
percentage of WTI. Prices are adjusted for quality,
transportation and a market-reflective negotiated differential.
We maximize the value of our condensate and heavier crudes by
determining whether to blend the condensate into our own crude
production or sell it in the market as a segregated product. We
transport crude oil on 12 pipelines to the major trading hubs
within Alberta and Saskatchewan, which enables us to achieve a
higher netback for the production and to diversify our
purchasers.
International
Apaches international assets are located in Egypt,
Australia, offshore the U.K. in the North Sea, Argentina and
Chile. In 2010 international assets contributed 52 percent
of our production and 56 percent of our oil and gas
production revenues. At year-end 30 percent of our
estimated proved reserves were located outside North America.
Egypt
Overview Our commitment to Egypt began in 1994
with our first Qarun discovery well. Today we control
11.3 million gross acres making Apache the largest acreage
holder in Egypts Western Desert. Only 15 percent of
our gross acreage in Egypt has been developed. That
15 percent produced an average of 189 Mb/d and
799 MMcf/d
in 2010, 99 Mb/d and
375 MMcf/d
net to Apache, which we believe makes Apache the largest
producer of liquid hydrocarbons and natural gas in the Western
Desert and the third largest in all of Egypt. The remaining
85 percent of our acreage is undeveloped, providing us with
considerable exploration and development opportunities for the
future. We have
3-D seismic
covering over 12,000 square miles, or 68 percent of
our acreage. In 2010 the region contributed 28 percent of
our production revenue, 24 percent of our production and
10 percent of our year-end estimated proved reserves. Our
estimated proved reserves in Egypt are reported under the
economic interest method and exclude the host country share
reserves.
Our operations in Egypt are conducted pursuant to
production-sharing agreements, in 24 separate concessions, under
which the contractor partner pays all operating and capital
expenditure costs for exploration and development. A percentage
of the production, usually up to 40 percent, is available
to the contractor partners to recover operating and capital
expenditure costs, with the balance generally allocated between
the contractor partners and Egyptian General Petroleum
Corporation (EGPC) on a contractually-defined basis. In 2010,
Apache retained approximately 52 percent and
47 percent, respectively, of the gross oil and gas produced
from our Egyptian concessions. Development leases within
concessions generally have a
25-year
life, with extensions possible for additional commercial
discoveries or on a negotiated basis, and currently have
expiration dates ranging from 10 to 25 years.
Apaches Egyptian operations had another year of growth in
2010: gross daily production increased 16 percent, and net
daily production increased six percent. We maintained an active
drilling and development program, drilling 204 wells,
including 10 new field discoveries, and conducted 662 workovers
and recompletions. In addition, we achieved a goal we set in
2005 to double gross equivalent production from our operated
concessions by the end of 2010. In November we closed on the
purchase of BP assets in Egypts Western Desert, acquiring
four development leases and one exploration concession as well
as strategically-positioned infrastructure that will enable
Apache to increase production from existing fields in the
Western Desert.
8
During 2011 the region plans to invest approximately
$1.1 billion for drilling, recompletion projects,
development projects, equipment upgrades, production enhancement
projects and seismic acquisition. Our drilling program includes
a combination of development and exploration wells with current
plans to drill 65 gross exploration wells, 50 percent
more than 2010. We will also drill our first horizontal well in
the Western Desert.
Egypt political unrest As a result of
political unrest, protests, riots, street demonstrations and
acts of civil disobedience in the Egyptian capital of Cairo that
began on January 25, 2011, Egyptian president Hosni Mubarak
stepped down, effective February 11, 2011. The Egyptian
Supreme Council of the Armed Forces is now in power. On
February 13, 2011, the Council announced that the
constitution would be suspended, both houses of parliament would
be dissolved, and that the military would rule for six months
until elections can be held. Following the advice of the
U.S. State Department, Apache initially evacuated all
non-essential personnel from Egypt. As conditions stabilized
recently, approximately one-third of the evacuated employees
returned. Apaches production, located in remote locations
in the Western Desert, has continued uninterrupted; however,
further changes in the political, economic and social conditions
or other relevant policies of the Egyptian government, such as
changes in laws or regulations, export restrictions,
expropriation of our assets or resource nationalization,
and/or
forced renegotiation or modification of our existing contracts
with EGPC could materially and adversely affect our business,
financial condition and results of operations.
Apache purchases multi-year political risk insurance from the
Overseas Private Investment Corporation (OPIC) and highly rated
international insurers covering its investments in Egypt. In the
aggregate, these policies, subject to the policy terms and
conditions, provide approximately $1 billion of coverage to
Apache covering losses arising from confiscation,
nationalization, and expropriation risks and currency
inconvertibility. In addition, the Company has a separate policy
with OPIC, which provides $300 million of coverage for
losses arising from (1) non-payment by EGPC of arbitral
awards covering amounts owed Apache on past due invoices and
(2) expropriation of exportable petroleum when actions
taken by the Government of Egypt prevent Apache form exporting
our share of production.
Marketing Our gas production is sold to EGPC
primarily under an industry-pricing formula, a sliding scale
based on Dated Brent crude oil with a minimum of $1.50 per MMBtu
and a maximum of $2.65 per MMBtu, which corresponds to a Dated
Brent price of $21.00 per barrel. Generally, this
industry-pricing formula applies to all new gas discovered and
produced. In exchange for extension of the Khalda Concession
lease in July 2004, Apache agreed to accept the industry-pricing
formula on a majority of gas sold, but retained the previous
gas-price formula (without a price cap) until 2013 for up to
100 MMcf/d
gross. This region averaged $3.62 per Mcf in 2010.
Oil from the Khalda Concession, the Qarun Concession and other
nearby Western Desert blocks is sold primarily to third parties
in the Mediterranean market or to EGPC when called upon to
supply domestic demand. Oil sales are made either directly into
the Egyptian oil pipeline grid, sold to non-governmental third
parties including those supplying the Middle East Oil Refinery
located in northern Egypt, or exported from or sold at one of
two terminals on the northern coast of Egypt. Oil production
that is presently sold to EGPC is sold on a spot basis priced at
Brent with a monthly EGPC official differential applied. In 2010
we sold 32 cargoes (approximately 10.1 MMbbls) of Western
Desert crude oil into the export market from the El Hamra
terminal located on the northern coast of Egypt. These export
cargoes were sold to third parties at market prices above our
domestic prices received from EGPC. Additionally, Apache sold
Qarun oil (approximately 10.7 MMbbls) at the Sidi Kerir
terminal, also located on the northern coast of Egypt. This
Qarun oil was sold at prevailing market prices into the domestic
market to non-governmental purchasers (1.3 MMbbls) or
exported primarily to refiners in the Mediterranean region (15
cargoes for approximately 9.4 MMbbls).
Australia
Overview Apaches holdings in Australia
are focused offshore Western Australia in the Carnarvon basin,
where we have operated since acquiring the gas processing
facilities on Varanus Island and adjacent producing properties
in 1993, the Exmouth basin and the Browse basin. We also have
exploration acreage in the Gippsland basin offshore southeastern
Australia. Production operations are concentrated in the
Carnarvon and Exmouth basins. In total, we control approximately
12.2 million gross acres in Australia through 35
exploration permits, 14
9
production licenses and six retention leases. In addition, we
have one production license and four retention leases pending
confirmation.
During the year the region participated in drilling
31 wells, of which 23 were productive. In addition, we
expanded our exploration opportunities in the Carnarvon and
Exmouth basins via farm-ins to seven permits. The transactions
resulted in a 58-percent increase in our net undeveloped acreage
in the Carnarvon basin and added 1.9 million net acres for
exploration in the Exmouth basin. Oil production increased by
369 percent on initial production from the development of
our 2007 Van Gogh and Pyrenees oil field discoveries, while gas
production increased by nine percent. Production from Australia
accounted for approximately 12 percent of our total 2010
production, and year-end estimated proved reserves were
11 percent of Apaches total.
The region has a pipeline of projects that are expected to
contribute to production growth as they are brought on-stream
over coming years.
In 2011, development of our Reindeer field discovery should be
complete with first production expected late in the year upon
completion of our Devil Creek Gas Plant. The plant will be
Western Australias third domestic natural gas processing
hub and the first new one in more than 15 years. The
two-train plant is designed to process 200 million cubic
feet of gas per day from the Apache-operated Reindeer field. In
2009, we entered into a gas sales contract covering a portion of
the fields future production. Under the contract, Apache
and its joint venture partner agreed to supply 154 Bcf of
gas over seven years (approximately
60 MMcf/d
beginning in the fourth quarter of 2011) at prices
substantially higher than we have historically received in
Western Australia. Apache owns a 55-percent interest in the
field. Also in 2011, initial production is projected from the
Halyard-1 discovery well which is a subsea completion tied back
to the existing gas facilities on Varanus Island.
In 2012, the 2010 Spar-2 discovery is projected to commence
production through an extension of the Halyard sub sea
infrastructure which will also allow for the tie-in of future
wells.
In 2013, first production is projected from four gas wells
completed in 2010 in the Macedon gas field. We have a
28 percent non-operating working interest in the field. Gas
will be delivered via a
60-mile
pipeline to a
200 MMcf/d
gas plant to be built at Ashburton North in Western Australia.
The project, approved in 2010, is currently underway; with first
production projected in 2013.
Also in 2013 first production is projected from the Coniston oil
field which lies just north of the Van Gogh field. The project
was sanctioned for development in 2010. Current plans call for
the field to be produced from subsea completions tied back to
the Van Gogh field floating, production, storage and offloading
(FPSO) Ningaloo Vision.
In 2014 first production from the Balnaves field is projected,
should the project proceed past Final Investment Decision (FID)
stage. The Balnaves field is an oil accumulation in the Brunello
gas field, where Apache drilled three successful development
wells which we plan to produce through a FPSO. The project is
currently in the Front End FEED stage with FID currently
projected for the second half of 2011.
In 2016 we are projecting to begin production from our operated
Julimar and Brunello field gas discoveries through the Chevron
operated Wheatstone LNG hub, in which we own a foundation equity
partner interest of 13 percent. Apaches projected net
gas sales from the fields are
160 MMcf/d
and 3,250 b/d with a projected
15-year
production plateau when the multi-year project is fully
operational. The project, which is currently in FEED, will
convert the gas into LNG for sale on the world market. World LNG
prices are typically oil-linked prices and are currently higher
than the historical gas prices in Western Australia. The project
FID is scheduled for 2011, with first LNG projected in 2016.
During 2011 the region plans to invest approximately
$1.2 billion for drilling, recompletion projects,
development projects, equipment upgrades, production enhancement
projects and seismic acquisition. Approximately half of the 2011
investment will be for development and processing facilities in
connection with the projects discussed above.
Marketing Western Australia has historically
had a local market for natural gas with a limited number of
buyers and sellers resulting in sales under mostly long-term,
fixed-price contracts, many of which contain periodic price
escalation clauses based on either the Australian consumer price
index or a commodity linkage. As of
10
December 31, 2010, Apache had a total of 18 active gas
contracts in Australia with expiration dates ranging from
November 2012 to July 2030. Recent increases in demand and
higher development costs have increased the supply prices
required from the local market in order to support the
development of new supplies. As a result, market prices received
on recent contracts, including our Reindeer field, are
substantially higher than historical levels.
We anticipate selling LNG from our Julimar and Brunello field
gas discoveries at prices tied to oil and sold into
international markets.
We directly market all of our Australian crude oil production
into Australian domestic and international markets at prices
generally indexed to Dated Brent benchmark crude oil prices plus
a premium, which are typically above NYMEX oil prices.
North
Sea
Overview Apache entered the North Sea in 2003
after acquiring an approximate 97-percent working interest in
the Forties field (Forties). In 2010 the North Sea region
produced 20.9 MMboe (99 percent oil), approximately
nine percent of our total worldwide production and
13 percent of Apaches oil and gas production
revenues. During 2010 production from Forties decreased seven
percent compared to 2009 as natural well decline and unplanned
maintenance downtime exceeded gains from drilling. At year-end
2010, Apache had total estimated proved reserves of
155 MMbbls of crude oil in this region, approximately five
percent of our year-end estimated proved reserves. Apache
acquired Forties with 45 producing wells. Today, there are 77
producing wells with an inventory of future locations. By the
end of the first quarter of 2010, Apache had produced and sold,
net to its interest, oil volumes in excess of the proved
reserves booked when we acquired this interest in 2003.
During the summer of 2010 a new
3-D seismic
survey was acquired in Forties. Comparison of this data with
3-D seismic
shot in prior years has highlighted many areas of bypassed oil
in the reservoir and provided better definition of existing
targets. In 2010, 20 wells were drilled into the Forties
reservoir, of which 12 were productive. We project that this
Forties success rate of 60 percent will increase in the
future, as drilling results from late December 2010 and early
January 2011 have validated the new
4-D
evaluation and geological interpretation. We also drilled three
exploration wells and one development well outside Forties. The
development well and one of the exploration wells were
successful.
In 2011 the region will invest approximately $850 million
on a diverse set of capital projects. Forties will see another
year of active drilling with two platform rigs and a
jack-up in
operation. Construction of the Forties Alpha Satellite Platform
is underway and is projected to be complete by mid-year 2012.
This platform will sit adjacent to the main Alpha Platform and
provide an additional 18 drilling slots along with power
generation, fluid separation, gas lift compression and oil
export pumping. Also, during the third quarter of 2011 drilling
will commence on the Bacchus field, Apaches first North
Sea subsea field development. First production is projected by
year-end of 2011. The region also expects to participate in at
least two exploration wells outside Forties.
In January 2011 a subsea pipeline connecting our Forties Bravo
platform to our Charlie platform was shut-in because of
corrosion. A project is underway to re-route the production
through a smaller line until a new flexible pipeline is
installed. This intermediate solution should be completed by the
first of March 2011 and will allow us to produce approximately
half of the 11,600 b/d that flowed through the main
pipeline. The new main subsea pipeline will be completed by
September 2011.
Marketing In 2010 we sold our Forties crude
under both term contracts (70 percent) and spot cargoes
(30 percent). The term sales are composed of a market-based
index plus a premium, which reflects the higher market value for
term arrangements. The prices received for spot cargoes are
market driven and can trade at a premium or discount to the
market based index.
All 2011 production will be sold under a term contract with a
per-barrel
premium to the Dated Brent index. A separate physical sales
contract within the term sale for 20,000 b/d was entered into
with a floor price of $70.00 per barrel and an average ceiling
price of $98.56 per barrel. This contract will be settled
against Dated Brent.
11
Argentina
Overview We have had a continuous presence in
Argentina since 2001, which was expanded substantially by two
acquisitions in 2006. We currently have operations in the
Provinces of Neuquén, Rio Negro, Tierra del Fuego and
Mendoza. We have interests in 24 concessions, exploration
permits and other interests totaling over 3.4 million gross
acres (2.9 million net). Apache now holds oil and gas
assets in three of the main Argentine hydrocarbon basins:
Neuquén, Austral and Cuyo. Our concessions have varying
expiration dates ranging from four years to over fifteen years
remaining, subject to potential additional extensions. In 2010
Argentina produced seven percent of our worldwide production and
held four percent of our estimated proved reserves at year-end.
In 2010 the region had its most successful development drilling
program in its history, drilling 56 gross wells:; 43 in the
Neuquén basin and 13 in the Austral basin of Tierra del
Fuego. Drilling focused on shallow development targets,
93 percent of the wells were successful. In addition, the
region completed 106 capital projects consisting of
recompletions, increasing lifting capacity, and facility
projects.
Also during 2010 Apache acquired approximately 567 square
kilometers of
3-D seismic
on two blocks located in the Cuyo basin. Apache employed new
cable-less technology intended to minimize environmental impact
in the area, the first time this technology has been used in
Argentina. We are currently analyzing the results from the
seismic shoot and expect to commence a drilling campaign in the
Cuyo basin in the first quarter of 2011.
In 2011 we will begin negotiations for extensions of three
concessions each in the Tierra del Fuego and Rio Negro
Provinces, which are scheduled to expire in 2016 and 2017.
Future investment by Apache in the Tierra del Fuego Province
will be significantly influenced by the probability of obtaining
the Provinces agreement to an extension of the present
concession expirations. In March 2009 Apache reached an
agreement with the Province of Neuquén to extend eight
federal oil and gas concessions for 10 additional years. The
concessions, which were scheduled to expire between 2015 and
2017, encompass approximately 590,000 net acres, including
exploratory areas totaling 514,000 net acres. Neuquén
operations generate about half of Apaches total output in
Argentina.
During 2011 the region plans to invest approximately
$300 million for drilling, recompletion projects,
development projects, equipment upgrades, production enhancement
projects, and seismic acquisition.
Marketing
Natural Gas Apache sells its natural gas
through three avenues:
|
|
|
|
|
Gas Plus program: This program was instituted by the Argentine
government to encourage new gas supplies through the development
of tight sands and unconventional reserves. Under this program,
qualifying projects are allowed to sell gas at prices that are
above the regulated rates. During 2010 Apache signed three Gas
Plus contracts totaling
63 MMcf/d
of gross production from fields in the Neuquén and Rio
Negro Provinces. The first contract, for
10 MMcf/d
at $4.10 per MMBtu for 2010, has been extended through 2011 for
11 MMcf/d
at the $4.10 per MMBtu. The other two contracts, which together
totaled
53 MMcf/d
at $5.00 per MMBtu, are expected to commence in the first
quarter of 2011. The gas supply is required to come from wells
drilled in the projects approved fields and formations. We
believe this program, reflects changing market conditions, which
point to improving markets and price realizations going forward.
|
|
|
|
Government-regulated pricing: The volumes we are required to
sell at regulated prices are set by the government and vary with
seasonal factors and industry category. During 2010 we realized
an average price of $1.20 per Mcf on government-regulated sales.
|
|
|
|
Unregulated market: The majority of our remaining volumes are
sold into the unregulated market. In 2010 realizations averaged
$2.65 per Mcf.
|
Crude Oil Our crude oil is subject to an
export tax, which effectively limits the prices buyers are
willing to pay for domestic sales. Domestic oil prices are
currently based on $42 per barrel, plus quality adjustments and
local premiums, and producers realize a gradual increase or
decrease as market prices deviate from the base price. In Tierra
del Fuego, similar pricing formulas exist; however, Apache
retains the value-added tax collected from buyers, effectively
increasing realized prices by 21 percent. As a result, 2010
oil prices realized from Tierra del
12
Fuego oil production averaged $65.03 per barrel as compared to
our Neuquén basin production, which averaged $53.68 per
barrel.
Chile
In November 2007 Apache was awarded exploration rights on two
blocks comprising approximately one million net acres on the
Chilean side of Tierra del Fuego. This acreage is adjacent to
our 552,000 net acres on the Argentine side of the island
of Tierra del Fuego and represents a natural extension of our
expanding exploration and production operations. The Lenga and
Rusfin Blocks were ratified by the Chilean government on
July 24, 2008. In January 2009 a
3-D seismic
survey totaling 1,000 square kilometers was completed, and
in November 2009 the first of a three-well exploration program
commenced drilling. The three wells have now been drilled, and
we are currently evaluating results.
Major
Customers
In 2010 purchases by Shell accounted for 15 percent of the
Companys worldwide oil and gas production revenues.
Drilling
Statistics
Worldwide in 2010 we participated in drilling 904 gross
wells, with 826 (91 percent) completed as producers. We
also performed nearly 2,500 workovers and recompletions during
the year. Historically, our drilling activities in the
U.S. have generally concentrated on exploitation and
extension of existing, producing fields rather than exploration.
As a general matter, our operations outside of the
U.S. focus on a mix of exploration and exploitation wells.
In addition to our completed wells, at year-end several wells
had not yet reached completion: 51 in the U.S. (25.04 net);
7 in Canada (6.18 net); 22 in Egypt (20 net); 2 in Australia
(0.64 net); 3 in the North Sea (2.91 net); and 7 in Argentina
(5.15 net).
13
The following table shows the results of the oil and gas wells
drilled and completed for each of the last three fiscal years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Exploratory
|
|
|
Net Development
|
|
|
Total Net Wells
|
|
|
|
Productive
|
|
|
Dry
|
|
|
Total
|
|
|
Productive
|
|
|
Dry
|
|
|
Total
|
|
|
Productive
|
|
|
Dry
|
|
|
Total
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
3.7
|
|
|
|
2.2
|
|
|
|
5.9
|
|
|
|
309.2
|
|
|
|
12.7
|
|
|
|
321.9
|
|
|
|
312.9
|
|
|
|
14.9
|
|
|
|
327.8
|
|
Canada
|
|
|
6.5
|
|
|
|
1.5
|
|
|
|
8.0
|
|
|
|
122.3
|
|
|
|
5.7
|
|
|
|
128.0
|
|
|
|
128.8
|
|
|
|
7.2
|
|
|
|
136.0
|
|
Egypt
|
|
|
19.4
|
|
|
|
18.5
|
|
|
|
37.9
|
|
|
|
144.8
|
|
|
|
5.5
|
|
|
|
150.3
|
|
|
|
164.2
|
|
|
|
24.0
|
|
|
|
188.2
|
|
Australia
|
|
|
5.5
|
|
|
|
3.4
|
|
|
|
8.9
|
|
|
|
4.5
|
|
|
|
1.3
|
|
|
|
5.8
|
|
|
|
10.0
|
|
|
|
4.7
|
|
|
|
14.7
|
|
North Sea
|
|
|
1.0
|
|
|
|
1.2
|
|
|
|
2.2
|
|
|
|
10.7
|
|
|
|
5.8
|
|
|
|
16.5
|
|
|
|
11.7
|
|
|
|
7.0
|
|
|
|
18.7
|
|
Argentina
|
|
|
1.8
|
|
|
|
2.7
|
|
|
|
4.5
|
|
|
|
43.3
|
|
|
|
0.3
|
|
|
|
43.6
|
|
|
|
45.1
|
|
|
|
3.0
|
|
|
|
48.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
37.9
|
|
|
|
29.5
|
|
|
|
67.4
|
|
|
|
634.8
|
|
|
|
31.3
|
|
|
|
666.1
|
|
|
|
672.7
|
|
|
|
60.8
|
|
|
|
733.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
5.6
|
|
|
|
2.5
|
|
|
|
8.1
|
|
|
|
107.6
|
|
|
|
8.5
|
|
|
|
116.1
|
|
|
|
113.2
|
|
|
|
11.0
|
|
|
|
124.2
|
|
Canada
|
|
|
3.0
|
|
|
|
|
|
|
|
3.0
|
|
|
|
136.8
|
|
|
|
12.8
|
|
|
|
149.6
|
|
|
|
139.8
|
|
|
|
12.8
|
|
|
|
152.6
|
|
Egypt
|
|
|
8.6
|
|
|
|
10.4
|
|
|
|
19.0
|
|
|
|
126.4
|
|
|
|
4.0
|
|
|
|
130.4
|
|
|
|
135.0
|
|
|
|
14.4
|
|
|
|
149.4
|
|
Australia
|
|
|
6.9
|
|
|
|
3.8
|
|
|
|
10.7
|
|
|
|
4.7
|
|
|
|
|
|
|
|
4.7
|
|
|
|
11.6
|
|
|
|
3.8
|
|
|
|
15.4
|
|
North Sea
|
|
|
1.0
|
|
|
|
|
|
|
|
1.0
|
|
|
|
12.6
|
|
|
|
2.9
|
|
|
|
15.5
|
|
|
|
13.6
|
|
|
|
2.9
|
|
|
|
16.5
|
|
Argentina
|
|
|
3.4
|
|
|
|
0.7
|
|
|
|
4.1
|
|
|
|
25.5
|
|
|
|
|
|
|
|
25.5
|
|
|
|
28.9
|
|
|
|
0.7
|
|
|
|
29.6
|
|
Other International
|
|
|
2.0
|
|
|
|
|
|
|
|
2.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.0
|
|
|
|
|
|
|
|
2.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
30.5
|
|
|
|
17.4
|
|
|
|
47.9
|
|
|
|
413.6
|
|
|
|
28.2
|
|
|
|
441.8
|
|
|
|
444.1
|
|
|
|
45.6
|
|
|
|
489.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
4.5
|
|
|
|
6.6
|
|
|
|
11.1
|
|
|
|
334.8
|
|
|
|
25.3
|
|
|
|
360.1
|
|
|
|
339.3
|
|
|
|
31.9
|
|
|
|
371.2
|
|
Canada
|
|
|
3.9
|
|
|
|
5.0
|
|
|
|
8.9
|
|
|
|
328.0
|
|
|
|
10.1
|
|
|
|
338.1
|
|
|
|
331.9
|
|
|
|
15.1
|
|
|
|
347.0
|
|
Egypt
|
|
|
18.7
|
|
|
|
11.5
|
|
|
|
30.2
|
|
|
|
193.2
|
|
|
|
5.8
|
|
|
|
199.0
|
|
|
|
211.9
|
|
|
|
17.3
|
|
|
|
229.2
|
|
Australia
|
|
|
6.4
|
|
|
|
9.0
|
|
|
|
15.4
|
|
|
|
12.5
|
|
|
|
|
|
|
|
12.5
|
|
|
|
18.9
|
|
|
|
9.0
|
|
|
|
27.9
|
|
North Sea
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.7
|
|
|
|
|
|
|
|
11.7
|
|
|
|
11.7
|
|
|
|
|
|
|
|
11.7
|
|
Argentina
|
|
|
7.5
|
|
|
|
2.0
|
|
|
|
9.5
|
|
|
|
54.4
|
|
|
|
6.2
|
|
|
|
60.6
|
|
|
|
61.9
|
|
|
|
8.2
|
|
|
|
70.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
41.0
|
|
|
|
34.1
|
|
|
|
75.1
|
|
|
|
934.6
|
|
|
|
47.4
|
|
|
|
982.0
|
|
|
|
975.6
|
|
|
|
81.5
|
|
|
|
1,057.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
Oil and Gas Wells
The number of productive oil and gas wells, operated and
non-operated, in which we had an interest as of
December 31, 2010, is set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Total
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
United States
|
|
|
5,165
|
|
|
|
3,040
|
|
|
|
2,370
|
|
|
|
7,995
|
|
|
|
17,535
|
|
|
|
11,035
|
|
Canada
|
|
|
10,100
|
|
|
|
8,405
|
|
|
|
2,500
|
|
|
|
1,100
|
|
|
|
12,600
|
|
|
|
9,505
|
|
Egypt
|
|
|
52
|
|
|
|
51
|
|
|
|
722
|
|
|
|
694
|
|
|
|
774
|
|
|
|
745
|
|
Australia
|
|
|
22
|
|
|
|
9
|
|
|
|
20
|
|
|
|
12
|
|
|
|
42
|
|
|
|
21
|
|
North Sea
|
|
|
|
|
|
|
|
|
|
|
77
|
|
|
|
75
|
|
|
|
77
|
|
|
|
75
|
|
Argentina
|
|
|
425
|
|
|
|
390
|
|
|
|
520
|
|
|
|
445
|
|
|
|
945
|
|
|
|
835
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
15,764
|
|
|
|
11,895
|
|
|
|
16,209
|
|
|
|
10,321
|
|
|
|
31,973
|
|
|
|
22,216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross natural gas and crude oil wells include 1,600 wells
with multiple completions.
14
Production, Pricing and Lease Operating Cost Data
The following table describes, for each of the last three fiscal
years, oil, NGLs and gas production, average lease operating
expenses per boe (including transportation costs but excluding
severance and other taxes) and average sales prices for each of
the countries where we have operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Lease
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
Operatinge Cost per
|
|
|
Average Sales Price
|
|
Year Ended December 31,
|
|
Oil
|
|
|
NGLs
|
|
|
Gas
|
|
|
Boe
|
|
|
Oil
|
|
|
NGLs
|
|
|
Gas
|
|
|
|
(MMbbls)
|
|
|
(MMbbls)
|
|
|
(Bcf)
|
|
|
|
|
|
(Per bbl)
|
|
|
(Per bbl)
|
|
|
(Per Mcf)
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
35.3
|
|
|
|
5.0
|
|
|
|
266.8
|
|
|
$
|
11.40
|
|
|
$
|
76.13
|
|
|
$
|
41.45
|
|
|
$
|
5.28
|
|
Canada
|
|
|
5.3
|
|
|
|
1.1
|
|
|
|
144.5
|
|
|
|
13.46
|
|
|
|
72.83
|
|
|
|
36.61
|
|
|
|
4.48
|
|
Egypt
|
|
|
36.2
|
|
|
|
|
|
|
|
136.8
|
|
|
|
5.56
|
|
|
|
79.45
|
|
|
|
69.75
|
|
|
|
3.62
|
|
Australia
|
|
|
16.7
|
|
|
|
|
|
|
|
72.9
|
|
|
|
6.41
|
|
|
|
77.32
|
|
|
|
|
|
|
|
2.24
|
|
North Sea
|
|
|
20.8
|
|
|
|
|
|
|
|
0.9
|
|
|
|
9.23
|
|
|
|
76.66
|
|
|
|
|
|
|
|
18.64
|
|
Argentina
|
|
|
3.6
|
|
|
|
1.2
|
|
|
|
67.5
|
|
|
|
7.97
|
|
|
|
57.47
|
|
|
|
27.08
|
|
|
|
1.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
117.9
|
|
|
|
7.3
|
|
|
|
689.4
|
|
|
|
9.20
|
|
|
|
76.69
|
|
|
|
38.58
|
|
|
|
4.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
32.5
|
|
|
|
2.2
|
|
|
|
243.1
|
|
|
$
|
10.59
|
|
|
$
|
59.06
|
|
|
$
|
33.02
|
|
|
|
4.34
|
|
Canada
|
|
|
5.5
|
|
|
|
0.8
|
|
|
|
131.1
|
|
|
|
11.46
|
|
|
|
56.16
|
|
|
|
25.54
|
|
|
|
4.17
|
|
Egypt
|
|
|
33.6
|
|
|
|
|
|
|
|
132.3
|
|
|
|
5.17
|
|
|
|
61.34
|
|
|
|
|
|
|
|
3.70
|
|
Australia
|
|
|
3.6
|
|
|
|
|
|
|
|
67.0
|
|
|
|
6.84
|
|
|
|
64.42
|
|
|
|
|
|
|
|
1.99
|
|
North Sea
|
|
|
22.3
|
|
|
|
|
|
|
|
1.0
|
|
|
|
8.19
|
|
|
|
60.91
|
|
|
|
|
|
|
|
13.15
|
|
Argentina
|
|
|
4.2
|
|
|
|
1.2
|
|
|
|
67.4
|
|
|
|
6.78
|
|
|
|
49.42
|
|
|
|
18.76
|
|
|
|
1.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
101.7
|
|
|
|
4.2
|
|
|
|
641.9
|
|
|
|
8.48
|
|
|
|
59.85
|
|
|
|
27.63
|
|
|
|
3.69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
32.9
|
|
|
|
2.2
|
|
|
|
248.8
|
|
|
$
|
12.62
|
|
|
$
|
83.70
|
|
|
$
|
58.62
|
|
|
$
|
8.86
|
|
Canada
|
|
|
6.3
|
|
|
|
0.7
|
|
|
|
129.1
|
|
|
|
14.00
|
|
|
|
93.53
|
|
|
|
49.33
|
|
|
|
7.94
|
|
Egypt
|
|
|
24.4
|
|
|
|
|
|
|
|
96.5
|
|
|
|
6.47
|
|
|
|
91.37
|
|
|
|
|
|
|
|
5.25
|
|
Australia
|
|
|
3.0
|
|
|
|
|
|
|
|
45.0
|
|
|
|
9.85
|
|
|
|
91.78
|
|
|
|
|
|
|
|
2.10
|
|
North Sea
|
|
|
21.8
|
|
|
|
|
|
|
|
1.0
|
|
|
|
10.00
|
|
|
|
95.76
|
|
|
|
|
|
|
|
18.78
|
|
Argentina
|
|
|
4.5
|
|
|
|
1.1
|
|
|
|
71.6
|
|
|
|
6.58
|
|
|
|
49.46
|
|
|
|
37.83
|
|
|
|
1.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
92.9
|
|
|
|
4.0
|
|
|
|
592.0
|
|
|
|
10.56
|
|
|
|
87.80
|
|
|
|
51.38
|
|
|
|
6.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
and Net Undeveloped and Developed Acreage
The following table sets out our gross and net acreage position
in each country where we have operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped Acreage
|
|
|
Developed Acreage
|
|
|
|
Gross Acres
|
|
|
Net Acres
|
|
|
Gross Acres
|
|
|
Net Acres
|
|
|
United States
|
|
|
4,809,425
|
|
|
|
2,846,337
|
|
|
|
4,955,265
|
|
|
|
2,848,363
|
|
Canada
|
|
|
3,834,513
|
|
|
|
2,960,531
|
|
|
|
4,527,542
|
|
|
|
3,334,602
|
|
Egypt
|
|
|
9,572,015
|
|
|
|
6,192,027
|
|
|
|
1,741,102
|
|
|
|
1,624,780
|
|
Australia
|
|
|
11,456,850
|
|
|
|
6,587,180
|
|
|
|
744,900
|
|
|
|
402,500
|
|
North Sea
|
|
|
780,811
|
|
|
|
406,157
|
|
|
|
41,019
|
|
|
|
39,846
|
|
Argentina
|
|
|
3,149,882
|
|
|
|
2,701,182
|
|
|
|
220,840
|
|
|
|
188,226
|
|
Chile
|
|
|
1,205,403
|
|
|
|
1,036,626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
34,808,899
|
|
|
|
22,730,730
|
|
|
|
12,230,668
|
|
|
|
8,438,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
As of December 31, 2010, we had 3,284,814, 1,588,390, and
3,552,045 net acres scheduled to expire by
December 31, 2011, 2012, and 2013, respectively, if
production is not established or we take no other action to
extend the terms. We plan to continue the terms of many of these
licenses and concession areas through operational or
administrative actions and do not project a significant portion
of our net acreage position to expire before such actions occur.
As of December 31, 2010, 30 percent of U.S. net
undeveloped acreage and 36 percent of Canadian undeveloped
acreage was held by production.
Estimated
Proved Reserves and Future Net Cash Flows
Effective December 31, 2009, Apache adopted revised oil and
gas disclosure requirements set forth by the SEC in Release
No. 33-8995,
Modernization of Oil and Gas Reporting and as
codified by the Financial Accounting Standards Board (FASB) in
Accounting Standards Codification (ASC) Topic 932,
Extractive Industries Oil and Gas. The
new rules include changes to the pricing used to estimate
reserves, the option to disclose probable and possible reserves,
revised definitions for proved reserves, additional disclosures
with respect to undeveloped reserves, and other new or revised
definitions and disclosures.
Proved oil and gas reserves are the estimated quantities of
natural gas, crude oil, condensate and NGLs that
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known
reservoirs under existing conditions, operating conditions, and
government regulations. The Company reports all estimated proved
reserves held under production-sharing arrangements utilizing
the economic interest method, which excludes the
host countrys share of reserves. Reserve estimates are
considered proved if they are economically producible and are
supported by either actual production or conclusive formation
tests. Estimated reserves that can be produced economically
through application of improved recovery techniques are included
in the proved classification when successful testing
by a pilot project or the operation of an active, improved
recovery program using reliable technology establishes the
reasonable certainty for the engineering analysis on which the
project or program is based. Economically producible means a
resource which generates revenue that exceeds, or is reasonably
expected to exceed, the costs of the operation. Reasonable
certainty means a high degree of confidence that the quantities
will be recovered. Reliable technology is a grouping of one or
more technologies (including computational methods) that has
been field-tested and has been demonstrated to provide
reasonably certain results with consistency and repeatability in
the formation being evaluated or in an analogous formation.
Estimated proved developed oil and gas reserves can be expected
to be recovered through existing wells with existing equipment
and operating methods.
PUD reserves include those reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for
recompletion. Undeveloped reserves may be classified as proved
reserves on undrilled acreage directly offsetting development
areas that are reasonably certain of production when drilled, or
where reliable technology provides reasonable certainty of
economic producibility. Undrilled locations may be classified as
having undeveloped reserves only if a development plan has been
adopted indicating that they are scheduled to be drilled within
five years, unless specific circumstances justify a longer time
period.
16
The following table shows proved oil, NGL and gas reserves as of
December 31, 2010, based on average commodity prices in
effect on the first day of each month in 2010, held flat for the
life of the production, except where future oil and gas sales
are covered by physical contract terms. The table shows reserves
on a boe basis in which natural gas is converted to an
equivalent barrel of oil based on a 6:1 energy equivalent ratio.
This ratio is not reflective of the current price ratio between
the two products.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
NGL
|
|
|
Gas
|
|
|
Total
|
|
|
|
(MMbbls)
|
|
|
(MMbbls)
|
|
|
(Bcf)
|
|
|
(MMboe)
|
|
|
Proved Developed:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
423
|
|
|
|
92
|
|
|
|
2,284
|
|
|
|
895
|
|
Canada
|
|
|
90
|
|
|
|
24
|
|
|
|
2,182
|
|
|
|
478
|
|
Egypt
|
|
|
110
|
|
|
|
|
|
|
|
748
|
|
|
|
234
|
|
Australia
|
|
|
48
|
|
|
|
|
|
|
|
683
|
|
|
|
162
|
|
North Sea
|
|
|
116
|
|
|
|
|
|
|
|
4
|
|
|
|
116
|
|
Argentina
|
|
|
16
|
|
|
|
6
|
|
|
|
462
|
|
|
|
100
|
|
Proved Undeveloped:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
214
|
|
|
|
30
|
|
|
|
989
|
|
|
|
409
|
|
Canada
|
|
|
57
|
|
|
|
4
|
|
|
|
1,310
|
|
|
|
280
|
|
Egypt
|
|
|
17
|
|
|
|
|
|
|
|
329
|
|
|
|
72
|
|
Australia
|
|
|
18
|
|
|
|
|
|
|
|
805
|
|
|
|
152
|
|
North Sea
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
39
|
|
Argentina
|
|
|
4
|
|
|
|
1
|
|
|
|
71
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL PROVED
|
|
|
1,152
|
|
|
|
157
|
|
|
|
9,867
|
|
|
|
2,953
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2010, Apache had total estimated proved
reserves of 1,309 MMbbls of crude oil, condensate and NGLs
and 9.9 Tcf of natural gas. Combined, these total estimated
proved reserves are the energy equivalent of 3.0 billion
barrels of oil or 17.7 Tcf of natural gas, of which oil
represents 39 percent. As of December 31, 2010, the
Companys proved developed reserves totaled
1,985 MMboe and estimated PUD reserves totaled
968 MMboe, or approximately 33 percent of worldwide
total proved reserves. Apache has elected not to disclose
probable or possible reserves in this filing.
The Companys estimates of proved reserves, proved
developed reserves and proved undeveloped reserves as of
December 31, 2010, 2009, 2008 and 2007, changes in
estimated proved reserves during the last three years, and
estimates of future net cash flows from proved reserves are
contained in Note 12 Supplemental Oil and Gas
Disclosures in the Notes to Consolidated Financial Statements
set forth in Part IV, Item 15 of this
Form 10-K.
Estimated future net cash flows as of December 31, 2010,
were calculated using a discount rate of 10 percent per
annum, end of period costs, and an unweighted arithmetic average
of commodity prices in effect on the first day of each month in
2010 and 2009, held flat for the life of the production, except
where prices are defined by contractual arrangements. Future net
cash flows as of December 31, 2008, were estimated using
commodity prices in effect at the end of that year, in
accordance with the SEC guidelines in effect prior to the
issuance of the Modernization Rules.
Proved
Undeveloped Reserves
The Companys total estimated PUD reserves of
968 MMboe as of December 31, 2010, increased by
237 MMboe over the 731 MMboe of PUD reserves estimated
at the end of 2009. This increase was, in part, due to our 2010
acquisitions described above. During the year, Apache converted
64 MMboe of PUD reserves to proved developed reserves
through development drilling activity. In North America we
converted 31 MMboe, with the remaining 33 MMboe in our
international areas.
During the year a total of approximately $1.1 billion was
spent on projects associated with reserves that were carried as
PUD reserves at the end of 2009. A portion of our costs
incurred each year relate to development projects that will be
converted to proved developed reserves in future years. We spent
$517 million on PUD reserve development activity in North
America and $574 million in the international areas. At
year-end 2010, no material amounts of PUD reserves remain
undeveloped for five years or more after they were initially
disclosed as PUD reserves.
17
Preparation
of Oil and Gas Reserve Information
Apache emphasizes that its reported reserves are reasonably
certain estimates which, by their very nature, are subject to
revision. These estimates are reviewed throughout the year and
revised either upward or downward, as warranted.
Apaches proved reserves are estimated at the property
level and compiled for reporting purposes by a centralized group
of experienced reservoir engineers that is independent of the
operating groups. These engineers interact with engineering and
geoscience personnel in each of Apaches operating areas
and with accounting and marketing employees to obtain the
necessary data for projecting future production, costs, net
revenues and ultimate recoverable reserves. All relevant data is
compiled in a computer database application, to which only
authorized personnel are given security access rights consistent
with their assigned job function. Reserves are reviewed
internally with senior management and presented to Apaches
Board of Directors in summary form on a quarterly basis.
Annually, each property is reviewed in detail by our centralized
and operating region engineers to ensure forecasts of operating
expenses, netback prices, production trends and development
timing are reasonable.
Apaches Executive Vice President of Corporate Reservoir
Engineering is the person primarily responsible for overseeing
the preparation of our internal reserve estimates and for
coordinating any reserves audits conducted by a third-party
engineering firm. He has a Bachelor of Science degree in
Petroleum Engineering and over 30 years of industry
experience with positions of increasing responsibility within
Apaches corporate reservoir engineering department. The
Executive Vice President of Corporate Reservoir Engineering
reports directly to our Chairman and Chief Executive Officer.
The estimate of reserves disclosed in this annual report on
Form 10-K
is prepared by the Companys internal staff, and the
Company is responsible for the adequacy and accuracy of those
estimates. However, the Company engages Ryder Scott Company,
L.P. Petroleum Consultants (Ryder Scott) to review our processes
and the reasonableness of our estimates of proved hydrocarbon
liquid and gas reserves. Apache selects the properties for
review by Ryder Scott based primarily on relative reserve value.
We also consider other factors such as geographic location, new
wells drilled during the year and reserves volume. During 2010
the properties selected for each country ranged from 63 to
100 percent of the total future net cash flows discounted
at 10 percent. These properties also accounted for over
85 percent of the reserves value of our international
proved reserves and of the new wells drilled in each country. In
addition, all fields containing five percent or more of the
Companys total proved reserves volume were included in
Ryder Scotts review. The review covered 63 percent of
total proved reserves; 72 percent of proved developed
reserves and 45 percent of proved undeveloped reserves.
Properties with proved undeveloped reserves generally have an
associated capital expenditure required to develop those
reserves included in their net present value calculation,
reducing their value relative to proved developed reserves. For
this reason those properties are less likely to be selected for
the audit, resulting in a higher percentage of proved developed
reserves selected for review.
During 2010, 2009, and 2008, Ryder Scotts review covered
72, 79 and 82 percent of the Companys worldwide
estimated proved reserves value and 63, 69, and 73 percent
of the Companys total proved reserves, respectively. Ryder
Scotts review of 2010 covered 59 percent of U.S.,
42 percent of Canada, 64 percent of Argentina,
99 percent of Australia, 83 percent of Egypt and
83 percent of the United Kingdoms total proved
reserves. Ryder Scotts review of 2009 covered
66 percent of U.S., 48 percent of Canada,
63 percent of Argentina, 96 percent of Australia,
86 percent of Egypt and 80 percent of the United
Kingdoms total proved reserves. Ryder Scotts review
of 2008 covered 70 percent of U.S., 51 percent of
Canada, 58 percent of Argentina, 100 percent of
Australia, 87 percent of Egypt and 89 percent of the
United Kingdoms total proved reserves. We have filed Ryder
Scotts independent report as an exhibit to this
Form 10-K.
According to Ryder Scotts opinion, based on their review,
including the data, technical processes and interpretations
presented by Apache, the overall procedures and methodologies
utilized by Apache in determining the proved reserves comply
with the current SEC regulations and the overall proved reserves
for the reviewed properties as estimated by Apache are, in
aggregate, reasonable within the established audit tolerance
guidelines as set forth in the Society of Petroleum Engineers
auditing standards.
18
Employees
On December 31, 2010, we had 4,449 employees.
Offices
Our principal executive offices are located at One Post Oak
Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas
77056-4400.
At year-end 2010 we maintained regional exploration
and/or
production offices in Tulsa, Oklahoma; Houston, Texas; Midland,
Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia;
Aberdeen, Scotland; and Buenos Aires, Argentina. Apache leases
all of its primary office space. The current lease on our
principal executive offices runs through December 31, 2013.
For information regarding the Companys obligations under
its office leases, please see Part II,
Item 7 Managements Discussion and
Analysis of Financial Condition and Results of
Operations Capital Resources and
Liquidity Contractual Obligations and
Note 8 Commitments and Contingencies in the
Notes to Consolidated Financial Statements set forth in
Part IV, Item 15 of this
Form 10-K.
Title
to Interests
As is customary in our industry, a preliminary review of title
records, which may include opinions or reports of appropriate
professionals or counsel, is made at the time we acquire
properties. We believe that our title to all of the various
interests set forth above is satisfactory and consistent with
the standards generally accepted in the oil and gas industry,
subject only to immaterial exceptions that do not detract
substantially from the value of the interests or materially
interfere with their use in our operations. The interests owned
by us may be subject to one or more royalty, overriding royalty,
or other outstanding interests (including disputes related to
such interests) customary in the industry. The interests may
additionally be subject to obligations or duties under
applicable laws, ordinances, rules, regulations, and orders of
arbitral or governmental authorities. In addition, the interests
may be subject to burdens such as production payments, net
profits interests, liens incident to operating agreements and
current taxes, development obligations under oil and gas leases,
and other encumbrances, easements, and restrictions, none of
which detract substantially from the value of the interests or
materially interfere with their use in our operations.
Additional
Information about Apache
In this section, references to we, us,
our, and Apache include Apache
Corporation and its consolidated subsidiaries, unless otherwise
specifically stated.
Remediation
Plans and Procedures
Apache adopted a Region Spill Response Plan (the Plan) for its
Gulf of Mexico operations to ensure a rapid and effective
response to spill events that may occur on Apache-operated
properties. Periodically, drills are conducted to measure and
maintain the effectiveness of the Plan. These drills include the
participation of spill response contractors, representatives of
the Clean Gulf Associates (CGA, described below), and
representatives of governmental agencies. The primary
association available to Apache in the event of a spill is CGA.
Apache has received approval for the Plan from the BOEMRE.
Apache personnel review the Plan annually and update where
necessary.
Apache is a member of, and has an employee representative on the
executive committee of, CGA, a
not-for-profit
association of producing and pipeline companies operating in the
Gulf of Mexico. CGA was created to provide a means of
effectively staging response equipment and providing immediate
spill response for its member companies operations in the
Gulf of Mexico. To this end, CGA has bareboat chartered (an
arrangement for the hiring of a boat with no crew or provisions
included) its marine equipment to the Marine Spill Response
Corporation (MSRC), a national, private,
not-for-profit
marine spill response organization, which is funded by grants
from the Marine Preservation Association. MSRC maintains
CGAs equipment (currently including 13 shallow water
skimmers, four fast response vessels with skimming capabilities,
nine fast response containment-skimming units, a large skimming
containment barge, numerous containment systems, wildlife
cleaning and rehabilitation facilities and dispersant inventory)
at various staging points around the Gulf of Mexico in its ready
state, and in the event of a spill, MSRC stands ready to
mobilize all of this equipment to CGA members. MSRC also handles
the maintenance and mobilization of CGA non-marine equipment. In
addition, CGA maintains a contract
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with Airborne Support Inc., which provides aircraft and
dispersant capabilities for CGA member companies. In 2010 we
paid CGA approximately $312,000: $12,800 per capita and a fee
based on annual production.
In the event that CGA resources are already being utilized,
other associations are available to Apache. Apache is a member
of Oil Spill Response Limited, which entitles any Apache entity
worldwide to access their service. Oil Spill Response Limited
has access to resources from the Global Response Network, a
collaboration of seven major oil industry funded spill response
organizations worldwide. Oil Spill Response Limited has
equipment stockpiles in Bahrain, Singapore and Southampton that
currently include approximately 153 skimmers, booms (of
approximately 12,000 meters), two Hercules aircraft for
equipment deployment and aerial dispersant spraying, two
additional aircraft, dispersant spray systems and dispersant,
floating storage tanks, all-terrain vehicles and various other
equipment. If necessary, Oil Spill Response Limiteds
resources may be, and have been, deployed to areas across the
globe, such as the Gulf of Mexico. In addition, resources of
other organizations are available to Apache as a non-member,
such as those of MSRC and National Response Corporation (NRC),
albeit at a higher cost. MSRC has an extensive inventory of oil
spill response equipment, independent of and in addition to
CGAs equipment, currently including 19 oil spill response
barges with storage capacities between 12,000 and
68,000 barrels, 68 shallow water barges, over 240 skimming
systems, six self-propelled skimming vessels, seven mobile
communication suites with internet and telephone connections, as
well as marine and aviation communication capabilities, various
small crafts and shallow water vessels and dispersant aircraft.
MSRC has contracts in place with many environmental contractors
around the country, in addition to hundreds of other companies
that provide support services during spill response. In the
event of a spill, MSRC will activate these contractors as
necessary to provide additional resources or support services
requested by its customers. NRC owns a variety of equipment,
currently including shallow water portable barges, boom, high
capacity skimming systems, inland work boats, vacuum transfer
units and mobile communication centers. NRC has access to a
vessel fleet of more than 328 offshore vessels and supply boats
worldwide, as well as access to hundreds of tugs and oil barges
from its tug and barge clients. The equipment and resources
available to these companies changes from
time-to-time
and current information is generally available on each of the
companies websites.
Apache participates in a number of industry-wide task forces
that are studying ways to better access and control blowouts in
subsea environments and increase containment and recovery
methods. Two such task forces are the Subsea Well Control and
Containment Task Force and the Offshore Operating Procedures
Task Force. In 2011, Apaches wholly-owned subsidiary
Apache Deepwater LLC, retained the Helix Energy Solution Group
in conjunction with its CGA membership, and will become a member
of the Marine Well Containment Company to fulfill the government
permit requirements for containment and oil spill response plans
in Deepwater operations.
Competitive
Conditions
The oil and gas business is highly competitive in the
exploration for and acquisitions of reserves, the acquisition of
oil and gas leases, equipment and personnel required to find and
produce reserves and in the gathering and marketing of oil, gas
and natural gas liquids. Our competitors include national oil
companies, major integrated oil and gas companies, other
independent oil and gas companies and participants in other
industries supplying energy and fuel to industrial, commercial
and individual consumers.
Certain of our competitors may possess financial or other
resources substantially larger than we possess or have
established strategic long-term positions and maintain strong
governmental relationships in countries in which we may seek new
entry. As a consequence, we may be at a competitive disadvantage
in bidding for leases or drilling rights.
However, we believe our diversified portfolio of core assets,
which comprises large acreage positions and well-established
production bases across six countries, and our balanced
production mix between oil and gas, our management and incentive
systems, and our experienced personnel give us a strong
competitive position relative to many of our competitors who do
not possess similar political, geographic and production
diversity. Our global position provides a large inventory of
geologic and geographic opportunities in the six countries in
which we have producing operations to which we can reallocate
capital investments in response to changes in local business
environments and markets. It also reduces the risk that we will
be materially impacted by an event in a specific area or country.
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Environmental
Compliance
As an owner or lessee and operator of oil and gas properties, we
are subject to numerous federal, provincial, state, local and
foreign country 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 the
lessee under an oil and gas lease for the cost of pollution
clean-up
resulting from operations, subject the lessee to liability for
pollution damages and require suspension or cessation of
operations in affected areas. Although environmental
requirements have a substantial impact upon the energy industry,
as a whole, we do not believe that these requirements affect us
differently, to any material degree, than other companies in our
industry.
We have made and will continue to make expenditures in our
efforts to comply with these requirements, which we believe are
necessary business costs in the oil and gas industry. We have
established policies for continuing compliance with
environmental laws and regulations, including regulations
applicable to our operations in all countries in which we do
business. We have established operating procedures and training
programs designed to limit the environmental impact of our field
facilities and identify and comply with changes in existing laws
and regulations. The costs incurred under these policies and
procedures are inextricably connected to normal operating
expenses such that we are unable to separate expenses related to
environmental matters; however, we do not believe expenses
related to training and compliance with regulations and laws
that have been adopted or enacted to regulate the discharge of
materials into the environment will have a material impact on
our capital expenditures, earnings or competitive position. In
November 2010 Apache entered into an agreed order with the Texas
Commission on Environmental Quality and paid a total of $111,000
in administrative penalties to settle allegations regarding
operations of two natural gas processing plants.
Changes to existing, or additions of, laws, regulations,
enforcement policies or requirements in one or more of the
countries or regions in which we operate could require us to
make additional capital expenditures. While the events in the
U.S. Gulf of Mexico in 2010 have resulted in the enactment
of, and may result in the enactment of additional, laws or
requirements regulating the discharge of materials into the
environment, we do not believe that any such regulations or laws
enacted or adopted as of this date will have a material adverse
impact on our cost of operations, earnings or competitive
position.
Our business activities and the value of our securities are
subject to significant hazards and risks, including those
described below. If any of such events should occur, our
business, financial condition, liquidity
and/or
results of operations could be materially harmed, and holders
and purchasers of our securities could lose part or all of their
investments. Additional risks relating to our securities may be
included in the prospectuses for securities we issue in the
future.
Future
economic conditions in the U.S. and key international markets
may materially adversely impact our operating
results.
The U.S. and other world economies are slowly recovering
from a global financial crisis and recession that began in 2008.
Growth has resumed but is modest and at an unsteady rate. There
are likely to be significant long-term effects resulting from
the recession and credit market crisis, including a future
global economic growth rate that is slower than in the years
leading up to the crisis, and more volatility may occur before a
sustainable, yet lower, growth rate is achieved. Global economic
growth drives demand for energy from all sources, including
fossil fuels. A lower future economic growth rate could result
in decreased demand growth for our crude oil and natural gas
production as well as lower commodity prices, which would reduce
our cash flows from operations and our profitability.
In addition, the Organisation for Economic Co-operation and
Development (OECD) has encouraged countries with large federal
budget deficits to initiate deficit reduction measures. Such
measures, if they are undertaken too rapidly, could further
undermine economic recovery and slow growth by reducing demand.
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Crude
oil and natural gas prices are volatile and a substantial
reduction in these prices could adversely affect our results and
the price of our common stock.
Our revenues, operating results and future rate of growth depend
highly upon the prices we receive for our crude oil and natural
gas production. Historically, the markets for crude oil and
natural gas have been volatile and are likely to continue to be
volatile in the future. For example, the NYMEX daily settlement
price for the prompt month oil contract in 2010 ranged from a
high of $92.89 per barrel to a low of $68.01 per barrel. The
NYMEX daily settlement price for the prompt month natural gas
contract in 2010 ranged from a high of $6.01 per MMBtu to a low
of $3.29 per MMBtu. The market prices for crude oil and natural
gas depend on factors beyond our control. These factors include
demand for crude oil and natural gas, which fluctuates with
changes in market and economic conditions, and other factors,
including:
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worldwide and domestic supplies of crude oil and natural gas;
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actions taken by foreign oil and gas producing nations;
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political conditions and events (including instability or armed
conflict) in crude oil or natural gas producing regions;
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the level of global crude oil and natural gas inventories;
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the price and level of imported foreign crude oil and natural
gas;
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the price and availability of alternative fuels, including coal
and biofuels;
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the availability of pipeline capacity and infrastructure;
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the availability of crude oil transportation and refining
capacity;
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weather conditions;
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electricity generation;
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domestic and foreign governmental regulations and taxes; and
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the overall economic environment.
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Significant declines in crude oil and natural gas prices for an
extended period may have the following effects on our business:
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limiting our financial condition, liquidity,
and/or
ability to fund planned capital expenditures and operations;
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reducing the amount of crude oil and natural gas that we can
produce economically;
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causing us to delay or postpone some of our capital projects;
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reducing our revenues, operating income and cash flows;
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limiting our access to sources of capital, such as equity and
long-term debt;
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a reduction in the carrying value of our crude oil and natural
gas properties; or
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a reduction in the carrying value of goodwill.
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We recorded asset impairment charges during 2008 and 2009. No
impairment charges were recorded during 2010. If commodity
prices decline, there could be additional impairments of our oil
and gas assets or other investments or an impairment of goodwill.
Our
ability to sell natural gas or oil and/or receive market prices
for our natural gas or oil may be adversely affected by pipeline
and gathering system capacity constraints and various
transportation interruptions.
A portion of our natural gas and oil production in any region
may be interrupted, or shut in, from time to time for numerous
reasons, including as a result of weather conditions, accidents,
loss of pipeline or gathering system
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access, field labor issues or strikes, or capital constraints
that limit the ability of third parties to construct gathering
systems, processing facilities or interstate pipelines to
transport our production, or we might voluntarily curtail
production in response to market conditions. If a substantial
amount of our production is interrupted at the same time, it
could temporarily adversely affect our cash flow.
Weather
and climate may have a significant adverse impact on our
revenues and productivity.
Demand for oil and natural gas are, to a significant degree,
dependent on weather and climate, which impact the price we
receive for the commodities we produce. In addition, our
exploration and development activities and equipment can be
adversely affected by severe weather, such as hurricanes in the
Gulf of Mexico or cyclones offshore Australia, which may cause a
loss of production from temporary cessation of activity or lost
or damaged equipment. Our planning for normal climatic
variation, insurance programs, and emergency recovery plans may
inadequately mitigate the effects of such weather, and not all
such effects can be predicted, eliminated or insured against.
Our
operations involve a high degree of operational risk,
particularly risk of personal injury, damage or loss of
equipment and environmental accidents.
Our operations are subject to hazards and risks inherent in the
drilling, production and transportation of crude oil and natural
gas, including:
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drilling well blowouts, explosions and cratering;
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pipeline ruptures and spills;
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fires;
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formations with abnormal pressures;
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equipment malfunctions; and
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hurricanes and/or cyclones, which could affect our operations in
areas such as on- and offshore the Gulf Coast and Australia, and
other natural disasters.
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Failure or loss of equipment, as the result of equipment
malfunctions or natural disasters such as hurricanes, could
result in property damages, personal injury, environmental
pollution and other damages for which we could be liable.
Litigation arising from a catastrophic occurrence, such as a
well blowout, explosion or fire at a location where our
equipment and services are used, may result in substantial
claims for damages. Ineffective containment of a drilling well
blowout or pipeline rupture could result in extensive
environmental pollution and substantial remediation expenses. If
a significant amount of our production is interrupted, our
containment efforts prove to be ineffective or litigation arises
as the result of a catastrophic occurrence, our cash flow and,
in turn, our results of operations could be materially and
adversely affected.
The
Devon and Mariner transactions have increased our exposure to
Gulf of Mexico operations.
Our recent acquisitions of oil and gas assets in offshore Gulf
of Mexico from Devon Energy Corporation and Mariner Energy, Inc.
have increased our exposure to offshore Gulf of Mexico
operations. Greater offshore concentration proportionately
increases risks from delays or higher costs common to offshore
activity, including severe weather, availability of specialized
equipment and compliance with environmental and other laws and
regulations.
In addition, as a result of the current lack of drilling
activity in the deepwater Gulf of Mexico and slowdown of
drilling activity on the Gulf of Mexico shelf caused by the
regulatory response to the Deepwater Horizon incident, drilling
equipment and oil field services companies may decide to exit
the Gulf of Mexico, making such services less available
and/or more
expensive once drilling activities are allowed to fully resume.
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Any
additional deepwater drilling laws and regulations, delays in
the processing and approval of permits and other related
developments in the Gulf of Mexico as well as our other
locations resulting from the Deepwater Horizon incident could
adversely affect Apaches business.
As has been widely reported, on April 20, 2010, a fire and
explosion occurred onboard the semisubmersible drilling rig
Deepwater Horizon, which lead to a significant oil spill that
affected the Gulf of Mexico. In response to this incident, the
BOEMRE ceased issuing drilling permits pursuant to a series of
moratoria, and all deepwater drilling activities in progress
were suspended. Although the moratoria have been lifted, the DOI
has not issued any permits related to the drilling of new
exploratory wells in the deepwater Gulf of Mexico as of
January 31, 2011. In 2010 the DOI issued new rules designed
to improve drilling and workplace safety, and various
Congressional committees began pursuing legislation to regulate
drilling activities and increase liability.
In January 2011 the Presidents National Commission on the
BP Deepwater Horizon Oil Spill and Offshore Drilling released
its report, recommending that the federal government require
additional regulation and an increase in liability caps. The
European Commission has recommended that new legislation be
enacted to enhance the safety of offshore oil and gas
activities. Additional legislation or regulation is being
discussed which could require companies operating in the Gulf of
Mexico to establish and maintain a higher level of financial
responsibility under its Certificate of Financial
Responsibility, a certificate required by the Oil Pollution Act
of 1990 which evidences a companys financial ability to
pay for cleanup and damages caused by oil spills. There have
also been discussions regarding the establishment of a new
industry mutual insurance fund in which companies would be
required to participate and which would be available to pay for
consequential damages arising from an oil spill. These
and/or other
legislative or regulatory changes could require us to maintain a
certain level of financial strength and may reduce our financial
flexibility.
The BOEMRE is expected to continue to issue new safety and
environmental guidelines or regulations for drilling in the Gulf
of Mexico, and other regulatory agencies could potentially issue
new safety and environmental guidelines or regulations in other
geographic regions, and may take other steps that could increase
the costs of exploration and production, reduce the area of
operations and result in permitting delays. We are monitoring
legislation and regulatory developments; however, it is
difficult to predict the ultimate impact of any new guidelines,
regulations or legislation. A prolonged suspension of drilling
activity in the U.S. and abroad and new regulations and
increased liability for companies operating in this sector could
adversely affect Apaches operations in the U.S. Gulf
of Mexico as well as in our other locations.
Our
commodity price risk management and trading activities may
prevent us from benefiting fully from price increases and may
expose us to other risks.
To the extent that we engage in price risk management activities
to protect ourselves from commodity price declines, we may be
prevented from realizing the full benefits of price increases
above the levels of the derivative instruments used to manage
price risk. In addition, our hedging arrangements may expose us
to the risk of financial loss in certain circumstances,
including instances in which:
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our production falls short of the hedged volumes;
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there is a widening of price-basis differentials between
delivery points for our production and the delivery point
assumed in the hedge arrangement;
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the counterparties to our hedging or other price risk management
contracts fail to perform under those arrangements; or
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a sudden unexpected event materially impacts oil and natural gas
prices.
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The
credit risk of financial institutions could adversely affect
us.
We have exposure to different counterparties, and we have
entered into transactions with counterparties in the financial
services industry, including commercial banks, investment banks,
insurance companies, other investment funds and other
institutions. These transactions expose us to credit risk in the
event of default of our counterparty. Deterioration in the
credit markets may impact the credit ratings of our current and
potential counterparties and
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affect their ability to fulfill their existing obligations to us
and their willingness to enter into future transactions with us.
We have exposure to financial institutions in the form of
derivative transactions in connection with our hedges and
insurance companies in the form of claims under our policies. In
addition, if any lender under our credit facility is unable to
fund its commitment, our liquidity will be reduced by an amount
up to the aggregate amount of such lenders commitment
under our credit facility.
We are
exposed to counterparty credit risk as a result of our
receivables.
We are exposed to risk of financial loss from trade, joint
venture, joint interest billing and other receivables. We sell
our crude oil, natural gas and NGLs to a variety of purchasers.
As operator, we pay expenses and bill our non-operating partners
for their respective shares of costs. Some of our purchasers and
non-operating partners may experience liquidity problems and may
not be able to meet their financial obligations. Nonperformance
by a trade creditor or non-operating partner could result in
significant financial losses.
A
downgrade in our credit rating could negatively impact our cost
of and ability to access capital.
We receive debt ratings from the major credit rating agencies in
the United States. Factors that may impact our credit ratings
include debt levels, planned asset purchases or sales and
near-term and long-term production growth opportunities.
Liquidity, asset quality, cost structure, product mix and
commodity pricing levels and others are also considered by the
rating agencies. A ratings downgrade could adversely impact our
ability to access debt markets in the future, increase the cost
of future debt and potentially require the Company to post
letters of credit for certain obligations.
Market
conditions may restrict our ability to obtain funds for future
development and working capital needs, which may limit our
financial flexibility.
During 2010 credit markets recovered but remain vulnerable to
unpredictable shocks. We have a significant development project
inventory and an extensive exploration portfolio, which will
require substantial future investment. We
and/or our
partners may need to seek financing in order to fund these or
other future activities. Our future access to capital, as well
as that of our partners and contractors, could be limited if the
debt or equity markets are constrained. This could significantly
delay development of our property interests.
Our
ability to declare and pay dividends is subject to
limitations.
The payment of future dividends on our capital stock is subject
to the discretion of our board of directors, which considers,
among other factors, our operating results, overall financial
condition, credit-risk considerations and capital requirements,
as well as general business and market conditions. Our board of
directors is not required to declare dividends on our common
stock and may decide not to declare dividends.
Any indentures and other financing agreements that we enter into
in the future may limit our ability to pay cash dividends on our
capital stock, including common stock. In the event that any of
our indentures or other financing agreements in the future
restrict our ability to pay dividends in cash on the mandatory
convertible preferred stock, we may be unable to pay dividends
in cash on the common stock unless we can refinance amounts
outstanding under those agreements. In addition, under Delaware
law, dividends on capital stock may only be paid from
surplus, which is defined as the amount by which our
total assets exceeds the sum of our total liabilities, including
contingent liabilities, and the amount of our capital; if there
is no surplus, cash dividends on capital stock may only be paid
from our net profits for the then current
and/or the
preceding fiscal year. Further, even if we are permitted under
our contractual obligations and Delaware law to pay cash
dividends on common stock, we may not have sufficient cash to
pay dividends in cash on our common stock.
Discoveries
or acquisitions of additional reserves are needed to avoid a
material decline in reserves and production.
The production rate from oil and gas properties generally
declines as reserves are depleted, while related
per-unit
production costs generally increase as a result of decreasing
reservoir pressures and other factors. Therefore, unless we add
reserves through exploration and development activities or,
through engineering studies,
25
identify additional behind-pipe zones, secondary recovery
reserves or tertiary recovery reserves, or acquire additional
properties containing proved reserves, our estimated proved
reserves will decline materially as reserves are produced.
Future oil and gas production is, therefore, highly dependent
upon our level of success in acquiring or finding additional
reserves on an economic basis. Furthermore, if oil or gas prices
increase, our cost for additional reserves could also increase.
We may
not realize an adequate return on wells that we
drill.
Drilling for oil and gas involves numerous risks, including the
risk that we will not encounter commercially productive oil or
gas reservoirs. The wells we drill or participate in may not be
productive, and we may not recover all or any portion of our
investment in those wells. The seismic data and other
technologies we use do not allow us to know conclusively prior
to drilling a well that crude or natural gas is present or may
be produced economically. The costs of drilling, completing and
operating wells are often uncertain, and 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 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; and
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increase in the cost of, or shortages or delays in the
availability of, drilling rigs and equipment.
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Future drilling activities may not be successful and, if
unsuccessful, this failure could have an adverse effect on our
future results of operations and financial condition. While all
drilling, whether developmental or exploratory, involves these
risks, exploratory drilling involves greater risks of dry holes
or failure to find commercial quantities of hydrocarbons.
Material
differences between the estimated and actual timing of critical
events may affect the completion and commencement of production
from development projects.
We are involved in several large development projects whose
completion may be delayed beyond our anticipated completion
dates. Our projects may be delayed by project approvals from
joint venture partners, timely issuances of permits and licenses
by governmental agencies, weather conditions, manufacturing and
delivery schedules of critical equipment, and other unforeseen
events. Delays and differences between estimated and actual
timing of critical events may adversely affect our large
development projects and our ability to participate in large
scale development projects in the future.
We may
fail to fully identify potential problems related to acquired
reserves or to properly estimate those reserves.
Although we perform a review of properties that we acquire that
we believe is consistent with industry practices, such reviews
are inherently incomplete. It generally is not feasible to
review in depth every individual property involved in each
acquisition. Ordinarily, we will focus our review efforts on the
higher-value properties and will sample the remainder. However,
even a detailed review of records and properties may not
necessarily reveal existing or potential problems, nor will it
permit us as a buyer to become sufficiently familiar with the
properties to assess fully and accurately their deficiencies and
potential. Inspections may not always be performed on every
well, and environmental problems, such as groundwater
contamination, are not necessarily observable even when an
inspection is undertaken. Even when problems are identified, we
often assume certain environmental and other risks and
liabilities in connection with acquired properties. There are
numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and future production rates and
costs with respect to acquired properties, and actual results
may vary substantially from those assumed in the estimates. In
addition, there can be no assurance
26
that acquisitions will not have an adverse effect upon our
operating results, particularly during the periods in which the
operations of acquired businesses are being integrated into our
ongoing operations.
The
Mariner and BP transactions have exposed us to additional risks
and uncertainties with respect to the acquired businesses and
their operations.
Although the acquired Mariner and BP businesses are generally
subject to risks similar to those to which we are subject in our
existing businesses, the Mariner and BP transactions may
increase these risks. For example, the increase in the scale of
our operations may increase our operational risks. The publicity
associated with the oil spill in the Gulf of Mexico resulting
from the fire and explosion onboard the Deepwater Horizon, which
was under contract to BP, may cause regulatory agencies to
scrutinize our operations more closely. This additional scrutiny
may adversely affect our operations.
We may
have difficulty combining the operations of both Mariner and the
BP properties, and the anticipated benefits of these
transactions may not be achieved.
Achieving the anticipated benefits of the Mariner and BP
transactions will depend in part upon whether we can
successfully integrate the operations of Mariner and the BP
properties with ours. Our ability to integrate the operations of
Mariner and the BP properties successfully will depend on our
ability to monitor operations, coordinate exploration and
development activities, control costs, attract, retain and
assimilate qualified personnel and maintain compliance with
regulatory requirements. The difficulties of integrating the
operations of Mariner and the BP properties may be increased by
the necessity of combining organizations with distinct cultures
and widely dispersed operations. The integration of operations
following these transactions will require the dedication of
management and other personnel, which may distract their
attention from the
day-to-day
business of the combined enterprise and prevent us from
realizing benefits from other opportunities. Completing the
integration process may be more expensive than anticipated, and
we cannot assure you that we will be able to effect the
integration of these operations smoothly or efficiently or that
the anticipated benefits of the transactions will be achieved.
Several
significant matters in the BP Acquisition were not resolved
before closing.
Because of the relatively short time period between signing the
BP Purchase Agreements and the closing of the acquisition of the
BP properties, several significant matters commonly resolved
prior to closing such an acquisition have been reserved for
after closing. We did not have sufficient time before closing on
the BP Properties to conduct a full title review and
environmental assessment. Although remedies are limited for
title, we may discover adverse environmental or other conditions
after closing and after the time periods specified in the BP
Purchase Agreements during which we may be able to seek, in
certain cases, indemnification from or cure of the defect or
adverse condition by BP for such matters. For example, Apache
Canada Ltd. has asserted a claim against BP Canada arising from
the acquisition of certain Canadian properties under the BP
Purchase Agreements. The dispute centers on Apache Canada
Ltd.s identification of Alleged Adverse Conditions, as
that term is defined in the BP Purchase Agreements, and more
specifically, the contention that liabilities associated with
such conditions were retained by BP Canada as seller. There can
be no assurance that we will prevail on this or any future claim
against BP.
The BP
Acquisition and/or our liabilities could be adversely affected
in the event one or more of the BP entities become the subject
of a bankruptcy case.
In light of the extensive costs and liabilities related to the
oil spill in the Gulf of Mexico in 2010, there was public
speculation as to whether one or more of the BP entities could
become the subject of a case or proceeding under Title 11
of the United States Code or any other relevant insolvency law
or similar law (which we collectively refer to as
Insolvency Laws). In the event that one or more of
the BP entities were to become the subject of such a case or
proceeding, a court may find that the BP Purchase Agreements are
executory contracts, in which case such BP entities may, subject
to relevant Insolvency Laws, have the right to reject the
agreements and refuse to perform their future obligations under
them. In this event, our ability to enforce our rights under the
BP Purchase Agreements could be adversely affected.
27
Additionally, in a case or proceeding under relevant Insolvency
Laws, a court may find that the sale of the BP Properties
constitutes a constructive fraudulent conveyance that should be
set aside. While the tests for determining whether a transfer of
assets constitutes a constructive fraudulent conveyance vary
among jurisdictions, such a determination generally requires
that the seller received less than a reasonably equivalent value
in exchange for such transfer or obligation and the seller was
insolvent at the time of the transaction, or was rendered
insolvent or left with unreasonably small capital to meet its
anticipated business needs as a result of the transaction. The
applicable time periods for such a finding also vary among
jurisdictions, but generally range from two to six years. If a
court were to make such a determination in a proceeding under
relevant Insolvency Laws, our rights under the BP Purchase
Agreements, and our rights to the BP Properties, could be
adversely affected.
Crude
oil and natural gas reserves are estimates, and actual
recoveries may vary significantly.
There are numerous uncertainties inherent in estimating crude
oil and natural gas reserves and their value, including factors
that are beyond our control. Reservoir engineering is a
subjective process of estimating underground accumulations of
crude oil and natural gas that cannot be measured in an exact
manner. In accordance with the SECs revisions to rules for
oil and gas reserves reporting, which we adopted effective
December 31, 2009, our reserves estimates are based on
12-month
average prices, except where contractual arrangements exist;
therefore, reserves quantities will change when actual prices
increase or decrease. The estimates depend on a number of
factors and assumptions that may vary considerably from actual
results, including:
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historical production from the area compared with production
from other areas;
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the assumed effects of regulations by governmental agencies,
including the impact of the SECs new oil and gas company
reserves reporting requirements;
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future operating costs;
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severance and excise taxes;
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development costs; and
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workover and remediation costs.
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For these reasons, estimates of the economically recoverable
quantities of crude oil and natural gas attributable to any
particular group of properties, classifications of those
reserves based on risk of recovery and estimates of the future
net cash flows expected from them prepared by different
engineers or by the same engineers but at different times may
vary substantially. Accordingly, reserves estimates may be
subject to upward or downward adjustment, and actual production,
revenue and expenditures with respect to our reserves likely
will vary, possibly materially, from estimates.
Additionally, because some of our reserves estimates are
calculated using volumetric analysis, those estimates are less
reliable than the estimates based on a lengthy production
history. Volumetric analysis involves estimating the volume of a
reservoir based on the net feet of pay of the structure and an
estimation of the area covered by the structure. In addition,
realization or recognition of proved undeveloped reserves will
depend on our development schedule and plans. A change in future
development plans for proved undeveloped reserves could cause
the discontinuation of the classification of these reserves as
proved.
Certain
of our undeveloped leasehold acreage is subject to leases that
will expire over the next several years unless production is
established on units containing the acreage.
A sizeable portion of our acreage is currently undeveloped.
Unless production in paying quantities is established on units
containing certain of these leases during their terms, the
leases will expire. If our leases expire, we will lose our right
to develop the related properties. Our drilling plans for these
areas are subject to change based upon various factors,
including drilling results, oil and natural gas prices, the
availability and cost of capital, drilling and production costs,
availability of drilling services and equipment, gathering
system and pipeline transportation constraints and regulatory
approvals.
28
We may
incur significant costs related to environmental
matters.
As an owner or lessee and operator of oil and gas properties, we
are subject to various federal, provincial, state, local and
foreign country 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 the
lessee under an oil and gas lease for the cost of pollution
clean-up
resulting from operations, subject the lessee to liability for
pollution damages and require suspension or cessation of
operations in affected areas. Our efforts to limit our exposure
to such liability and cost may prove inadequate and result in
significant adverse effect on our results of operations. In
addition, it is possible that the increasingly strict
requirements imposed by environmental laws and enforcement
policies could require us to make significant capital
expenditures. Such capital expenditures could adversely impact
our cash flows and our financial condition.
Our
North American operations are subject to governmental risks that
may impact our operations.
Our North American operations have been, and at times in the
future may be, affected by political developments and by
federal, state, provincial and local laws and regulations such
as restrictions on production, changes in taxes, royalties and
other amounts payable to governments or governmental agencies,
price or gathering rate controls and environmental protection
laws and regulations. New political developments, laws and
regulations may adversely impact our results on operations.
Pending
regulations related to emissions and the impact of any changes
in climate could adversely impact our business.
Legislation is pending in a number of countries where Apache
operates including Australia, and Canada, the United Kingdom,
that, if enacted, could tax or assess some form of greenhouse
gas (GHG) related fees on Company operations and could lead to
increased operating expenses. Such legislation, if enacted,
could also potentially cause the Company to make significant
capital investments for infrastructure modifications. Through
2011, three of the jurisdictions in which the Company has
operations, Alberta and British Columbia, Canada and the United
Kingdom (European Union), have enacted legislation which exposes
the Company to financial payments related to GHG emissions from
production facilities. This exposure has not been material to
date.
Furthermore, various governmental entities in countries where
Apache operates have discussed regulatory initiatives that
could, if adopted, require the Company to modify existing or
planned infrastructure to meet GHG emissions performance
standards and necessitate significant capital expenditures. At
some level, the cost of performance standards may force the
early retirement of smaller production facilities, which in
aggregate may have a material adverse effect on Apaches
business.
Several of the countries we operate in are signatories to
current international accords related to climate change, such as
the Kyoto Protocol to the United Nations Framework Convention on
Climate Change. Given the current implementation of the Kyoto
Protocol, we do not expect it to have a material impact on the
Company.
Several indirect consequences of regulation and business trends
have potential to impact us. Taxes or fees on carbon emissions
could lead to decreased demand for fossil fuels. Consumers may
prefer alternative products and unknown technological
innovations may make oil and gas less significant energy sources.
In the event the predictions for rising temperatures and sea
levels suggested by reports of the United Nations
Intergovernmental Panel on Climate Change do transpire, we do
not believe those events by themselves are likely to impact the
Companys assets or operations. However, any increase in
severe weather could have a material adverse effect on our
assets and operations.
The
proposed U.S. federal budget for fiscal year 2012 includes
certain provisions that, if passed as originally submitted, will
have an adverse effect on our financial position, results of
operations, and cash flows.
On February 14, 2011, the Office of Management and Budget
released a summary of the proposed U.S. federal budget for
fiscal year 2012. The proposed budget repeals many tax
incentives and deductions that are currently used by
U.S. oil and gas companies and imposes new taxes. The
provisions include: elimination of the ability to fully
29
deduct intangible drilling costs in the year incurred; increases
in the taxation of foreign source income; repeal of the
manufacturing tax deduction for oil and natural gas companies;
and an increase in the geological and geophysical amortization
period for independent producers. Should some or all of these
provisions become law, our taxes will increase, potentially
significantly, which would have a negative impact on our net
income and cash flows. This could also cause us to reduce our
drilling activities in the U.S. Since none of these
proposals have yet to be voted on or become law, we do not know
the ultimate impact these proposed changes may have on our
business.
Proposed
federal regulation regarding hydraulic fracturing could increase
our operating and capital costs.
Several proposals are before the U.S. Congress that, if
implemented, would either prohibit the practice of hydraulic
fracturing or subject the process to regulation under the Safe
Drinking Water Act. We routinely use fracturing techniques in
the U.S. and other regions to expand the available space
for natural gas and oil to migrate toward the well-bore. It is
typically done at substantial depths in very tight formations.
Although it is not possible at this time to predict the final
outcome of the legislation regarding hydraulic fracturing, any
new federal restrictions on hydraulic fracturing that may be
imposed in areas in which we conduct business could result in
increased compliance costs or additional operating restrictions
in the U.S.
A
deterioration of conditions in Egypt or changes in the economic
and political environment in Egypt could have an adverse impact
on our business.
In 2010 our operations in Egypt contributed 28 percent of
our production revenue, 25 percent of total production and
10 percent of total estimated proved reserves. In 2010 we
sold all of our Egyptian gas production and 34 percent of
our Egyptian oil production to the Egyptian General Petroleum
Company (EGPC), the Egyptian state-owned oil company, and sold
the remainder in the export market. As a result of political
unrest, protests, riots, street demonstrations and acts of civil
disobedience that began on January 25, 2011, in the
Egyptian capital of Cairo, former Egyptian president Hosni
Mubarak has stepped down, effective February 11, 2011. The
Egyptian Supreme Council of the Armed Forces is now in power. On
February 13, 2011, the Council announced that the
constitution would be suspended, both houses of parliament would
be dissolved, and that the military would rule for six months
until elections can be held. Further changes in the political,
economic and social conditions or other relevant policies of the
Egyptian government, such as changes in laws or regulations,
export restrictions, expropriation of our assets or resource
nationalization,
and/or
forced renegotiation or modification of our existing contracts
with EGPC could materially and adversely affect our business,
financial condition and results of operations.
International
operations have uncertain political, economic and other
risks.
Our operations outside North America are based primarily in
Egypt, Australia, the United Kingdom and Argentina. On a barrel
equivalent basis, approximately 52 percent of our 2010
production was outside North America and approximately
30 percent of our estimated proved oil and gas reserves on
December 31, 2010 were located outside North America. As a
result, a significant portion of our production and resources
are subject to the increased political and economic risks and
other factors associated with international operations
including, but not limited to:
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general strikes and civil unrest;
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the risk of war, acts of terrorism, expropriation and resource
nationalization, 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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price control;
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transportation regulations and tariffs;
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constrained natural gas markets dependent on demand in a single
or limited geographical area;
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30
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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, especially
foreign oil ministries and national oil companies, to the
jurisdiction of courts in the United States; and
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difficulties in 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 in which we operate 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 investments such as ours. In an extreme case, such a
change could result in termination of contract rights and
expropriation of our 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 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.
In recent weeks civil unrest, which started in Tunisia, has
spread to the Middle East. Prolonged
and/or
widespread regional conflict in the Middle East could have the
following results, among others:
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volatility in the global crude prices, which could negatively
impact the global economy, resulting in slower economic growth
rates, which could reduce demand for our products;
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negative impact on the worlds crude oil supply if
transportation avenues are disrupted, leading to further
commodity price volatility;
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damage to or destruction of our wells, production facilities,
receiving terminals or other operating assets;
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inability of our service equipment providers to deliver items
necessary for us to conduct our operations in the Middle East;
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lack of availability of drilling rigs, oil field equipment or
services if third party providers decide to exit the region.
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Our
operations are sensitive to currency rate
fluctuations.
Our operations are sensitive to fluctuations in foreign currency
exchange rates, particularly between the U.S. dollar and
the Canadian dollar, the Australian dollar and the British
Pound. Our financial statements, presented in U.S. dollars,
are affected by foreign currency fluctuations through both
translation risk and transaction risk. Volatility in exchange
rates may adversely affect our results of operation,
particularly through the weakening of the U.S. dollar
relative to other currencies.
We
face strong industry competition that may have a significant
negative impact on our result of operations.
Strong competition exists in all sectors of the oil and gas
exploration and production industry. We compete with major
integrated and other independent oil and gas companies for
acquisition of oil and gas leases, properties and
31
reserves, equipment and labor required to explore, develop and
operate those properties and marketing of oil and natural gas
production. Crude oil and natural gas prices impact the costs of
properties available for acquisition and the number of companies
with the financial resources to pursue acquisition
opportunities. Many of our competitors have financial and other
resources substantially larger than we possess and have
established strategic long-term positions and maintain strong
governmental relationships in countries in which we may seek new
entry. As a consequence, we may be at a competitive disadvantage
in bidding for drilling rights. In addition, many of our larger
competitors may have a competitive advantage when responding to
factors that affect demand for oil and natural gas production,
such as fluctuating worldwide commodity prices and levels of
production, the cost and availability of alternative fuels and
the application of government regulations. We also compete in
attracting and retaining personnel, including geologists,
geophysicists, engineers and other specialists. These
competitive pressures may have a significant negative impact on
our results of operations.
Our
insurance policies do not cover all of the risks we face, which
could result in significant financial exposure.
Exploration for and production of crude oil and natural gas can
be hazardous, involving natural disasters and other events such
as blowouts, cratering, fire and explosion and loss of well
control which can result in damage to or destruction of wells or
production facilities, injury to persons, loss of life, or
damage to property and the environment. Our international
operations are also subject to political risk. The insurance
coverage that we maintain against certain losses or liabilities
arising from our operations may be inadequate to cover any such
resulting liability; moreover, insurance is not available to us
against all operational risks.
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ITEM 1B.
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UNRESOLVED
SEC STAFF COMMENTS
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As of December 31, 2010, we did not have any unresolved
comments from the SEC staff that were received 180 or more days
prior to year-end.
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ITEM 3.
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LEGAL
PROCEEDINGS
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The information set forth under Legal Matters and
Environmental Matters in Note 8
Commitments and Contingencies in the Notes to Consolidated
Financial Statements set forth in Part IV, Item 15 of
this
Form 10-K
is incorporated herein by reference.
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ITEM 4.
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[REMOVED
AND RESERVED]
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32
PART II
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ITEM 5.
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MARKET
FOR THE REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
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During 2010 Apache common stock, par value $0.625 per share, was
traded on the New York and Chicago Stock Exchanges and the
NASDAQ National Market under the symbol APA. The
table below provides certain information regarding our common
stock for 2010 and 2009. Prices were obtained from The New York
Stock Exchange, Inc. Composite Transactions Reporting System.
Per-share prices and quarterly dividends shown below have been
rounded to the indicated decimal place.
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2010
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2009
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Price Range
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Dividends Per Share
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Price Range
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Dividends Per Share
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High
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Low
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Declared
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Paid
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High
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Low
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Declared
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Paid
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First Quarter
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$
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108.92
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$
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95.15
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$
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.15
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$
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.15
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$
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88.07
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$
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51.03
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$
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.15
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$
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.15
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Second Quarter
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111.00
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83.55
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.15
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.15
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87.04
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61.60
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.15
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.15
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Third Quarter
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99.09
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81.94
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.15
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.15
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95.77
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65.02
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.15
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.15
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Fourth Quarter
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120.80
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96.51
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.15
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.15
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106.46
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88.06
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.15
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.15
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The closing price of our common stock, as reported on the New
York Stock Exchange Composite Transactions Reporting System for
January 31, 2011 (last trading day of the month), was
$119.36 per share. As of January 31, 2011, there were
382,752,217 shares of our common stock outstanding held by
approximately 5,700 stockholders of record and approximately
440,000 beneficial owners.
We have paid cash dividends on our common stock for 46
consecutive years through December 31, 2010. When, and if,
declared by our Board of Directors, future dividend payments
will depend upon our level of earnings, financial requirements
and other relevant factors.
In 1995, under our stockholder rights plan, each of our common
stockholders received a dividend of one preferred stock purchase
right (a right) for each 2.310 outstanding shares of
common stock (adjusted for subsequent stock dividends and a
two-for-one
stock split) that the stockholder owned. These rights were
originally scheduled to expire on January 31, 2006.
Effective as of that date, the rights were reset to one right
per share of common stock, and the expiration was extended to
January 31, 2016. Unless the rights have been previously
redeemed, all shares of Apache common stock are issued with
rights, which trade automatically with our shares of common
stock. For a description of the rights, please refer to
Note 7 Capital Stock in the Notes to
Consolidated Financial Statements set forth in Part IV,
Item 15 of this
Form 10-K.
Information concerning securities authorized for issuance under
equity compensation plans is set forth under the caption
Equity Compensation Plan Information in the proxy
statement relating to the Companys 2010 annual meeting of
stockholders, which is incorporated herein by reference.
33
The following stock price performance graph is intended to allow
review of stockholder returns, expressed in terms of the
appreciation of the Companys common stock relative to two
broad-based stock performance indices. The information is
included for historical comparative purposes only and should not
be considered indicative of future stock performance. The graph
compares the yearly percentage change in the cumulative total
stockholder return on the Companys common stock with the
cumulative total return of the Standard & Poors
Composite 500 Stock Index and of the Dow Jones
U.S. Exploration & Production Index (formerly Dow
Jones Secondary Oil Stock Index) from December 31, 2005,
through December 31, 2010.
COMPARISON
OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Apache Corporation, S&P 500 Index
and the Dow Jones US Exploration & Production
Index
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2005
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2006
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2007
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2008
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2009
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2010
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Apache Corporation
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$
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100.00
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$
|
97.70
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$
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159.16
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$
|
111.05
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$
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154.93
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$
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180.12
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S & Ps Composite 500 Stock Index
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100.00
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115.79
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122.16
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76.96
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|
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97.33
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|
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111.99
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DJ US Expl& Prod Index
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100.00
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105.37
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151.39
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90.65
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127.42
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148.14
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* $100 invested on 12/31/05 in stock including reinvestment
of dividends.
Fiscal year ending December 31.
34
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ITEM 6.
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SELECTED
FINANCIAL DATA
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The following table sets forth selected financial data of the
Company and its consolidated subsidiaries over the five-year
period ended December 31, 2010, which information has been
derived from the Companys audited financial statements.
This information should be read in connection with, and is
qualified in its entirety by, the more detailed information in
the Companys financial statements set forth in
Part IV, Item 15 of this
Form 10-K.
As discussed in more detail under Item 15, the 2009 numbers
in the following table reflect a $2.82 billion
($1.98 billion net of tax) non-cash write-down of the
carrying value of the Companys U.S. and Canadian
proved oil and gas properties as of March 31, 2009, as a
result of ceiling test limitations. The 2008 numbers reflect a
$5.3 billion ($3.6 billion net of tax) non-cash
write-down of the carrying value of the Companys U.S.,
U.K. North Sea, Canadian and Argentine proved oil and gas
properties as of December 31, 2008.
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As of or for the Year Ended December 31,
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2010
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2009
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2008
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2007
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2006
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(In millions, except per share amounts)
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Income Statement Data
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|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
12,092
|
|
|
$
|
8,615
|
|
|
$
|
12,390
|
|
|
$
|
9,999
|
|
|
$
|
8,309
|
|
Income (loss) attributable to common stock
|
|
|
3,000
|
|
|
|
(292
|
)
|
|
|
706
|
|
|
|
2,807
|
|
|
|
2,547
|
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
8.53
|
|
|
|
(.87
|
)
|
|
|
2.11
|
|
|
|
8.45
|
|
|
|
7.72
|
|
Diluted
|
|
|
8.46
|
|
|
|
(.87
|
)
|
|
|
2.09
|
|
|
|
8.39
|
|
|
|
7.64
|
|
Cash dividends declared per common share
|
|
|
.60
|
|
|
|
.60
|
|
|
|
.70
|
|
|
|
.60
|
|
|
|
.50
|
|
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
43,425
|
|
|
$
|
28,186
|
|
|
$
|
29,186
|
|
|
$
|
28,635
|
|
|
$
|
24,308
|
|
Long-term debt
|
|
|
8,095
|
|
|
|
4,950
|
|
|
|
4,809
|
|
|
|
4,012
|
|
|
|
2,020
|
|
Shareholders equity
|
|
|
24,377
|
|
|
|
15,779
|
|
|
|
16,509
|
|
|
|
15,378
|
|
|
|
13,191
|
|
Common shares outstanding
|
|
|
382
|
|
|
|
336
|
|
|
|
335
|
|
|
|
333
|
|
|
|
331
|
|
For a discussion of significant acquisitions and divestitures,
see Note 2 Significant Acquisitions and
Divestitures in the Notes to Consolidated Financial Statements
set forth in Part IV, Item 15 of this
Form 10-K.
35
|
|
ITEM 7.
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
Apache Corporation, a Delaware corporation formed in 1954, is an
independent energy company that explores for, develops and
produces natural gas, crude oil and natural gas liquids. We
currently have exploration and production interests in seven
countries: the U.S., Egypt, Australia, offshore the U.K. in the
North Sea (North Sea), Argentina and Chile.
The following discussion should be read together with the
Consolidated Financial Statements and the Notes to Consolidated
Financial Statements set forth in Part IV, Item 15 of
this
Form 10-K,
and the Risk Factors information set forth in Part I,
Item 1A of this
Form 10-K.
Executive
Overview
Strategy
Apaches mission is to grow a profitable global exploration
and production company in a safe and environmentally responsible
manner for the long-term benefit of our shareholders.
Apaches long-term perspective has many dimensions, with
the following core strategic components:
|
|
|
|
|
balanced portfolio of core assets;
|
|
|
|
conservative capital structure; and
|
|
|
|
rate of return focus.
|
A cornerstone of our strategy is balancing our portfolio through
diversity of geologic risk, geographic risk, hydrocarbon mix
(crude oil versus natural gas) and reserve life in order to
achieve consistency in results. Our portfolio of geographic
locations provides variation of all of these factors and,
additionally, in the case of Australia and Argentina, the
potential for increasing the value of our investments through
rising natural gas prices. By maintaining a balanced hydrocarbon
mix, we are protecting against price deterioration in a given
product while retaining upside potential through a significant
increase in either commodity price. For example, in 2010 oil and
liquids provided 52 percent of our production but
77 percent of our total oil and gas revenues. We were well
positioned to realize the benefit of higher oil prices, enabling
record financial results despite North America natural gas
prices that were under pressure most of the year.
Each operating region has a significant producing asset base as
well as large undeveloped acreage positions which provide room
for growth through sustainable lower-risk drilling
opportunities, balanced by higher-risk, higher-reward
exploration. We closely monitor drilling and acquisition cost
trends in each of our core areas relative to product prices and,
when appropriate, adjust our budgets accordingly. We review
capital allocations, at least quarterly, through a disciplined
and focused process of reviewing internally-generated drilling
prospects, opportunities for tactical acquisitions, land
positions with additional drilling prospects or, occasionally,
new core areas which could enhance our portfolio. In addition,
we actively seek to identify and pursue ways to maintain
efficient levels of costs and expenses. Our overall approach to
managing cash expenditures has enabled us to consistently
deliver strong results with 2010 return on average capital
employed and return on equity of 12 percent and
15 percent, respectively.
Preserving financial flexibility is also important to our
overall business philosophy. We ended 2010 with a year-end
debt-to-capitalization
ratio of 25 percent, an increase of only one percent from
the prior year despite current-year capital investments of
$17 billion, including acquisitions totaling more than
$11 billion.
Throughout the cycles of our industry, these strategic
principles have underpinned our ability to deliver production,
reserve growth and competitive investment rates of return for
the benefit of our shareholders. Delivering successful results
under this strategy is bolstered by Apaches unique
culture. A strong sense of urgency, empowerment of our
employees, effective incentive systems and an independent
mindset are at the heart of how we build value.
36
Financial
and Operating Results
While Apache has grown into a much larger company than it was a
year ago, we have stayed true to our business model, focusing on
rate of return and cash-generating assets. Although the year
2010 will be remembered for the level of acquisition activity,
the record financial results reflected continued growth and
positive returns. For the
12-month
period ending December 31, 2010, Apache reported record
performances in several key metrics. Highlights for the year
include:
|
|
|
|
|
Annual daily production of oil, natural gas, and natural gas
liquids averaged a record 658,000 boe/d, up 13 percent
compared with 2009. Production in fourth-quarter 2010 averaged
729,000 boe/d, an increase of 24 percent from the 590,000
boe/d averaged in the fourth quarter of 2009.
|
|
|
|
Oil and gas production revenues for 2010 increased
42 percent to $12.1 billion, up from $8.6 billion
in 2009, and just shy of the record $12.3 billion in 2008
when prices reached record levels.
|
|
|
|
Apache reported a record $3 billion in net income, or $8.46
per common diluted share, compared to a net loss of
$292 million, or $.87 per share in the 2009 period.
Apaches 2009 results were impacted by a $1.98 billion
after-tax write-down of the carrying value of proved property.
Apaches 2010 reported adjusted earnings(1), which exclude
certain items impacting the comparability of results, were
approximately $3.17 billion or $8.94 per common diluted
share, up from $1.89 billion or $5.59 per common diluted
share in the prior year.
|
|
|
|
Net cash provided by operating activities (operating cash flows
or cash flows) totaled $6.7 billion, up 60 percent
from $4.2 billion in 2009.
|
|
|
|
Estimated proved reserves at year-end 2010 were a record
2,953 MMboe, up 25 percent from 2009 estimated proved
reserves of 2,367 MMboe.
|
(1) See Non-GAAP Measures Adjusted Earnings
for a description of Adjusted Earnings, which is not a
U.S. Generally Accepted Accounting Principles (GAAP)
measure, and a reconciliation to this measure from Income (Loss)
Attributable to Common Stock, which is presented in accordance
with GAAP.
2011
Outlook
As we head into 2011, we project Apaches financial
position will remain strong, given our
debt-to-capitalization
ratio of 25 percent, $2.4 billion of available
committed borrowing capacity, projections of higher cash flows
than 2010 levels and determination to hold exploration and
development spending within our internally-generated cash flows.
Given the present price disparity between oil and natural gas,
our near-term focus is exploiting the oily and more liquids-rich
properties in our portfolio and development of our gas resources
in Australia and Canada, which we plan to convert to LNG and
sell in the worldwide LNG market. As is the Apache way, rates of
return will drive our decision making while we continue our
focus on costs, operational efficiency and integrating the
acquired assets. In 2011 we find ourselves with more
opportunities than we can fund through internally-generated cash
flow, and our challenge will be to optimize capital spending
across our worldwide portfolio.
Our current 2011 capital budget includes exploration and
development capital of approximately $7.5 billion. Nearly
$4.0 billion is expected to be spent on projects in North
America, with the remaining amount allocated across our
international regions. An estimated one-third of our global
capital budget is allocated to seismic and leasehold, GTP
facilities and plugging and abandonment activities. While funds
have been committed for certain 2011 exploration drilling,
long-lead development projects and FEED studies, the majority of
our drilling and development projects are discretionary and
subject to acceleration, deferral or cancellation as conditions
warrant. We closely monitor commodity prices, service cost
levels, regulatory impacts and other numerous industry factors
and will adjust our exploration and development budgets based on
changes to predicted operating cash flow. We typically review
and revise our exploration and development capital budgets on a
quarterly basis.
Based on the current capital spending budget and the
acquisitions completed during 2010, Apache expects to increase
overall production in 2011 between 13 percent and
17 percent from full-year 2010 production levels. These
projections exclude the impact from any potential acquisitions
or divestitures.
37
The Company is currently planning to divest approximately
$1.0 billion of properties to optimize and high-grade our
existing portfolio of assets. The divestiture package will most
likely include legacy conventional properties in Canada.
However, as of the date of this filing we have not entered into
any binding contracts to sell these assets. We generally do not
budget for acquisitions because they are specific, discrete
events whose occurrence and timing is unpredictable.
Acquisitions may be funded from operating cash flows, credit
facilities, new equity, debt issuances or a combination thereof.
Operating
Highlights
Current
Year
During 2010 we completed more than $11 billion of
acquisitions, continued progress on developing existing core
properties and expanded into new geographic areas. Through these
steps, we added significantly to drilling inventory in our core
areas and established a footprint in two new areas: deepwater
exploration and LNG, which for us means the monetization of
large gas resources at oil-linked prices.
Merger
and Acquisitions of Property and Acreage
From 2007 to 2009 we were relatively absent from the acquisition
market. We believed the market was overheated as oil and gas
prices spiked, and the opportunities we identified did not meet
our criteria for risk, reward
and/or
growth potential. We built our cash position while drilling our
existing inventory of prospects and waiting for the right
transactions to supplement it.
|
|
|
|
|
In June we completed the $1.05 billion acquisition of Devon
Energy Corporations oil and gas assets on the Gulf of
Mexico (GOM) shelf, 75 percent of which are in fields now
operated by Apache. The acquired assets include 477,000 net
acres across 150 blocks. The Company believes that these
well-maintained, high-quality assets fit well with Apaches
existing infrastructure and play to the strengths that come with
our experience operating on the shelf, exploiting the current
production base and capturing upside potential.
|
|
|
|
In August we completed the $2.5 billion acquisition of oil
and gas operations, acreage and infrastructure in the Permian
Basin from BP plc (BP), solidifying our position as one of the
most active operators in the area, where Apache has been
competing for 20 years. The acquisition more than doubled
our footprint in the Permian Basin to over three million gross
acres.
|
|
|
|
In October we completed the $3.25 billion acquisition of
substantially all of BPs upstream natural gas business in
western Alberta and British Columbia, including 1.3 million
net mineral and leasehold acres with significant positions in
several emerging unconventional plays, such as the Noel
tight-gas project, which ramped up to
100 MMcf/d
by the end of the fourth quarter. We own a 100-percent working
interest in the Noel project.
|
|
|
|
In November we closed on the purchase of BP assets in
Egypts Western Desert for $650 million, acquiring
four development leases and one exploration concession as well
as strategically-positioned infrastructure that will enable
Apache to increase production from existing fields in the
Western Desert.
|
|
|
|
Also in November, shareholders of Mariner Energy, Inc. (Mariner)
approved the purchase of their company by Apache for stock and
cash consideration totaling $2.7 billion. We also assumed
approximately $1.7 billion of Mariners debt with the
merger. Apache established a strategic presence in the deepwater
Gulf of Mexico and expanded our positions in the GOM shelf, Gulf
Coast and Permian Basin with the acquisition. The acquisition
also provides deepwater geoscience expertise, including a core
competency in subsea tieback developments, which can
significantly reduce the cycle time between exploration success
and initial production.
|
|
|
|
During the first quarter of 2010 Apache Canada Ltd. (Apache
Canada), through its subsidiaries, closed the acquisition of a
51-percent interest in a planned LNG export terminal (Kitimat
LNG facility) and a 25.5-percent interest in a partnership that
owns a related proposed pipeline. EOG Resources Canada, Inc.
(EOG
|
38
|
|
|
|
|
Canada) owns the remaining 49 percent of the Kitimat LNG
facility and a 24.5-percent interest in the pipeline
partnership. In February 2011 Apache Canada and EOG Canada
entered into an agreement to purchase the remaining 50-percent
interest in the partnership. Upon close of the transaction,
Apache Canada and EOG Canada will own 51 percent and
49 percent, respectively, of the pipeline partnership and
proposed pipeline.
|
|
|
|
|
|
In Australia, during 2010 we expanded our exploration
opportunities in the Carnarvon and Exmouth basins via farm-ins
to seven permits. The transactions resulted in a
58-percent
increase in our net undeveloped acreage in the Carnarvon basin
and added 1.9 million acres for exploration in the Exmouth
basin. We will operate all of them with a 20- to 70-percent
working interest.
|
|
|
|
In the North Sea, we expanded our acreage position during the
year through successful bids on four exploration licenses and
farming into two additional licenses with a 50-percent working
interest.
|
Egypt 2X
Gross Production Achievement
Apaches Egypt operations had another year of growth in
2010, with gross daily production rising 16 percent to
322.5 Mboe/d and net daily production rising six percent to an
average of 161.7 Mboe/d for the year. During the year the
Company surpassed its late-2005 goal of doubling its Western
Desert production within five years. Achievement of the goal was
driven in part by production from several discoveries in the
Faghur and Matruh basins, infrastructure improvements including
two new Salam gas trains, expansion of the capacity of the
Kalabsha oil processing and transportation facilities to 40,000
b/d and completion of a major strategic compression project on
Egypts northern gas pipeline. The Faghur and Matruh
basins, where the thickness of the sands and the stacked pay
zones present multiple opportunities for further exploration
across our acreage, will continue to be focus areas for Apache
in 2011.
Van Gogh
and Pyrenees Oil Fields Development
Australias 2010 production averaged a record 79.2 Mboe/d,
driven by the Apache-operated Van Gogh oil field and BHP
Billiton-operated Pyrenees oil field, both of which commenced
production early in 2010. The Van Gogh and Pyrenees developments
utilize Floating Production Storage and Offloading (FPSO)
vessels and together added 42.2 Mb/d to Apaches
2010 net oil production. Both projects have already reached
payout.
Organic
Growth Drivers 2011 to 2013
Australia
Reindeer Field Development and Devil Creek Gas Plant
Our Reindeer field discovery is projected to commence production
in 2011 upon completion of the Devil Creek Gas Plant. The Devil
Creek Gas Plant is scheduled to be commissioned in the fourth
quarter of 2011. This will be Western Australias first new
domestic natural gas processing hub in more than 15 years.
The two-train plant is designed to process
200 MMcf/d
from the Apache-operated Reindeer Field. In 2009 we entered into
a gas sales contract covering a portion of the fields
future production. Under the contract, Apache and our joint
venture partner agreed to supply 154 Bcf of gas over seven
years (approximately
60 MMcf/d)
beginning in the fourth quarter of 2011 at prices substantially
higher than we have historically received in Western Australia.
Apache owns a 55-percent interest in the field.
Australia
Halyard Field Development
Initial production from our Halyard-1 discovery well in
Australia is projected for 2011 upon completion of the tie-in to
the existing gas facilities on Varanus Island. The extension of
this subsea infrastructure will also connect the 2010 Spar-2
discovery and allow for tie-in of future wells.
North Sea
Satellite Platform
In November Apache entered into a contract to build a new
satellite oil production platform for our UK Forties field. The
new platform will be bridge-linked to our existing Forties Alpha
installation in the Apache-operated field, located on the U.K.
continental shelf. This project will provide Apache with 18 new
slots for drilling additional development wells to increase the
ultimate recovery from the Forties field. The satellite platform
will also expand
39
critical utility services to the field, including power
generation, produced fluid processing, high-pressure gas
compression for artificial lift and dehydration. Construction is
projected to be complete by mid-year 2012.
Australia
Macedon Field Development
The Macedon gas fields four development wells, which were
completed in 2010, will be delivered via a
60-mile
pipeline to a
200 MMcf/d
gas plant to be built at Ashburton North in Western Australia.
We have a 28-percent non-operated working interest in the field.
The project, approved in 2010, is currently underway, with first
production projected in 2013.
Australia
Coniston Oil Field Discovery
The Coniston field is an oil accumulation near our Van Gogh
field in Australia. Apache drilled 10 appraisal wells during
2009, and current plans call for subsea completions tied back to
the Van Gogh field FPSO Ningaloo Vision. The project has been
sanctioned for development, with first production into the
domestic market projected in 2013.
North
America Unconventional Gas Plays
The identification and development of significant resources in
shale formations and other unconventional gas plays have
introduced substantial gas supplies into North American natural
gas markets for the foreseeable future. Although Apaches
current production in North America is primarily conventional,
near-term gas production growth will likely be driven by our
activity in three large unconventional plays: shale gas in
British Columbias Horn River basin, tight sands in British
Columbias Noel area and the Granite Wash tight sands in
the Anadarko basin of Oklahoma and the Texas Panhandle.
Horizontal
Drilling and Completion Techniques
Apache continues to evaluate horizontal drilling potential
across our acreage positions around the world, in both
conventional and unconventional reservoirs. In the Permian
Basin, Apache is utilizing horizontal drilling to access
bypassed, unswept zones in established waterfloods. We are
currently drilling our first horizontal shale well in Argentina,
targeted for completion in April. In addition, we plan to drill
our first horizontal well in the Western Desert of Egypt in
2011. The Company will continue to evaluate our opportunities
utilizing horizontal drilling technology.
Organic
Growth Drivers 2014 and Beyond
Australia
Balnaves Oil Field Discovery Development
In October 2010 we announced three successful wells appraising
our Balnaves-1 discovery, an oil accumulation in a separate
reservoir beneath the large gas reservoirs of our Brunello gas
fields (discussed below). The project is currently in the FEED
stage, with plans to develop the field through a new FPSO. First
production, if the decision is made to go forward with the
project, is projected for 2014.
Julimar
and Brunello Field Discoveries Development/Wheatstone LNG
Project
In 2016, we are projecting to begin production from our operated
Julimar and Brunello field gas discoveries through the Chevron
operated Wheatstone LNG hub, in which we own a foundation equity
partner interest of 13 percent. Apaches projected net
gas sales from the fields are
160 MMcf/d
and 3,250 b/d with a projected
15-year
production plateau when the multi-year project is fully
operational. The Wheatstone project, which is currently in FEED,
will convert the gas into LNG for sale on the world market.
World LNG prices are typically oil-linked prices and are
currently higher than the historical gas prices in Western
Australia. The project Final Investment Decision (FID) is
scheduled for 2011, with first LNG projected in 2016. Nonbinding
Heads of Agreements have been signed with LNG buyers and final
binding sales and purchase agreements will be completed by FID.
40
Kitimat/Horn
River Basin Development
Apaches time horizon and magnitude of our Horn River basin
shale gas development is impacted by North American gas prices
and the completion of the Kitimat LNG facility and a related
proposed pipeline. The project has the potential to open new
markets linked to oil prices in the Asia-Pacific region for gas
from Apaches Canadian operations, including the Horn River
basin area in northeast British Columbia. Apache Canada and EOG
Canada plan to build the Kitimat LNG facility on Bish Cove near
the Port of Kitimat, 400 miles north of Vancouver, British
Columbia. The facility is planned for an initial minimum
capacity of
700 MMcf/d,
or five million metric tons of LNG per year, of which Apache
Canada has reserved 51 percent. The proposed
287-mile
pipeline will originate in Summit Lake, British Columbia, and is
designed to link the Kitimat LNG facility to the pipeline system
currently servicing western Canadas natural gas producing
regions. Apache Canada will have rights to 51-percent of the
capacity in the proposed pipeline. Completion of the FEED study
and a final investment decision are targeted for late 2011.
Construction is expected to commence in 2012, with commercial
operations projected to begin in 2015.
GOM
Deepwater
Apache has built deepwater experience and a record of success in
Egypt, Australia and the Gulf of Mexico, on both the exploration
and development sides. The GOM deepwater portfolio gained in the
Mariner merger adds over 100 blocks and offers a strategic
position into a significant potential growth area in the United
States that can add meaningful oil reserves and production over
the long term. Exploration potential is generated from
Mariners extensive track record of 36 deepwater
development projects completed to date and the technological
developments in seismic and facilities making exploration more
predictable, lower risk and lower cost. Our pipeline of
development projects include the non-operated Heidelberg
(12.5-percent net working interest) and Lucius (16.67-percent
net working interest) discoveries, which are still under further
appraisal and study for ultimate development.
Significant
Events
Impact
of Deepwater Drilling Moratorium on Gulf of Mexico
Operations
In 2010 the Bureau of Ocean Energy Management, Regulation and
Enforcement (BOEMRE) announced a series of moratoria, which
directed oil and gas lessees and operators to cease drilling new
deepwater (depths greater than 500 feet) wells on the Outer
Continental Shelf (OCS), and put oil and gas lessees and
operators on notice that, with certain exceptions, the BOEMRE
would not consider drilling permits for deepwater wells and
related activities. While the moratoria have been formally
lifted, no new permits for deepwater drilling have been issued
as of the date of this filing.
In addition, the BOEMRE issued new regulations in 2010 requiring
additional information, documentation and analysis for all new
wells on the OCS. The effect of these new regulations was to
significantly slow down issuance of permits for shallow wells.
Apache continues to operate under these new regulations and,
through February 2011, has received 25 drilling permits for
shallow wells. Current permitting activity has been slowed
compared to prior-year levels, and the Company has budgeted its
exploration and development activity accordingly.
Impact
of Recent Political Changes on Egyptian Operations
In 2010 our operations in Egypt contributed 28 percent of
our production revenue, 25 percent of total production and
10 percent of total estimated proved reserves. In 2010 we
sold all of our Egyptian gas production and 34 percent of
our Egyptian oil production to Egyptian General Petroleum
Company (EGPC), the Egyptian state-owned oil company. The
remainder of our oil was sold in the export market.
As a result of political unrest, protests, riots, street
demonstrations and acts of civil disobedience that began on
January 25, 2011, in the Egyptian capital of Cairo,
Egyptian president Hosni Mubarak stepped down, effective
February 11, 2011. The Egyptian Supreme Council of the
Armed Forces assumed power. On February 13, 2011, the
Council announced that the constitution would be suspended, both
houses of parliament would be dissolved, and the military would
rule for six months until elections can be held. Following the
advice of the U.S. State Department, Apache evacuated all
non-essential personnel from Egypt. As conditions stabilized,
approximately one-third of the
41
evacuated employees returned. Apaches production, located
in remote locations in the Western Desert, has continued
uninterrupted; however, further changes in the political,
economic and social conditions or other relevant policies of the
Egyptian government, such as changes in laws or regulations,
export restrictions, expropriation of our assets or resource
nationalization
and/or
forced renegotiation or modification of our existing contracts
with EGPC could materially and adversely affect our business,
financial condition and results of operations.
Apache purchases multi-year political risk insurance from the
Overseas Private Investment Corporation (OPIC) and highly rated
international insurers covering its investments in Egypt. In the
aggregate, these policies, subject to the policy terms and
conditions, provide approximately $1 billion of coverage to
Apache covering losses arising from confiscation,
nationalization, and expropriation risks and currency
inconvertibility. In addition, the Company has a separate policy
with OPIC, which provides $300 million of coverage for
losses arising from (1) non-payment by EGPC of arbitral
awards covering amounts owed Apache on past due invoices and
(2) expropriation of exportable petroleum when actions
taken by the Government of Egypt prevent Apache from exporting
our share of production.
Operations
Downtime
Production from our Van Gogh oil field was impacted by essential
maintenance activities on the FPSO. Net fourth quarter
production of 6,100 b/d was down 17,600 b/d from the previous
quarter. Production resumed in the first half of February 2011.
In January 2011 a subsea pipeline connecting our Forties Bravo
platform to our Charlie platform was shut-in because of
corrosion. A project is underway to re-route the production
through a smaller line until a new flexible pipeline is
installed. This intermediate solution should be completed by the
first of March 2011 and will allow us to produce approximately
half of the 11,600 b/d that flowed through the main pipeline.
The new main subsea pipeline will be completed by September 2011.
42
Results
of Operations
Oil
and Gas Revenues
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For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
%
|
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|
%
|
|
|
|
|
|
%
|
|
|
|
$ Value
|
|
|
Contribution
|
|
|
$ Value
|
|
|
Contribution
|
|
|
$ Value
|
|
|
Contribution
|
|
|
|
(In millions)
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Oil Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
2,683
|
|
|
|
30
|
%
|
|
$
|
1,922
|
|
|
|
32
|
%
|
|
$
|
2,751
|
|
|
|
34
|
%
|
Canada
|
|
|
388
|
|
|
|
4
|
%
|
|
|
311
|
|
|
|
5
|
%
|
|
|
587
|
|
|
|
7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
3,071
|
|
|
|
34
|
%
|
|
|
2,233
|
|
|
|
37
|
%
|
|
|
3,338
|
|
|
|
41
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt
|
|
|
2,875
|
|
|
|
32
|
%
|
|
|
2,063
|
|
|
|
34
|
%
|
|
|
2,232
|
|
|
|
27
|
%
|
Australia
|
|
|
1,296
|
|
|
|
14
|
%
|
|
|
230
|
|
|
|
4
|
%
|
|
|
277
|
|
|
|
3
|
%
|
North Sea
|
|
|
1,590
|
|
|
|
18
|
%
|
|
|
1,356
|
|
|
|
22
|
%
|
|
|
2,085
|
|
|
|
26
|
%
|
Argentina
|
|
|
209
|
|
|
|
2
|
%
|
|
|
207
|
|
|
|
3
|
%
|
|
|
225
|
|
|
|
3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
5,970
|
|
|
|
66
|
%
|
|
|
3,856
|
|
|
|
63
|
%
|
|
|
4,819
|
|
|
|
59
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(2)
|
|
$
|
9,041
|
|
|
|
100
|
%
|
|
$
|
6,089
|
|
|
|
100
|
%
|
|
$
|
8,157
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
1,409
|
|
|
|
49
|
%
|
|
$
|
1,054
|
|
|
|
44
|
%
|
|
$
|
2,204
|
|
|
|
56
|
%
|
Canada
|
|
|
647
|
|
|
|
23
|
%
|
|
|
546
|
|
|
|
23
|
%
|
|
|
1,026
|
|
|
|
26
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
2,056
|
|
|
|
72
|
%
|
|
|
1,600
|
|
|
|
67
|
%
|
|
|
3,230
|
|
|
|
82
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt
|
|
|
495
|
|
|
|
17
|
%
|
|
|
490
|
|
|
|
21
|
%
|
|
|
507
|
|
|
|
13
|
%
|
Australia
|
|
|
163
|
|
|
|
6
|
%
|
|
|
133
|
|
|
|
6
|
%
|
|
|
95
|
|
|
|
2
|
%
|
North Sea
|
|
|
16
|
|
|
|
0
|
%
|
|
|
13
|
|
|
|
0
|
%
|
|
|
18
|
|
|
|
0
|
%
|
Argentina
|
|
|
132
|
|
|
|
5
|
%
|
|
|
133
|
|
|
|
6
|
%
|
|
|
115
|
|
|
|
3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
806
|
|
|
|
28
|
%
|
|
|
769
|
|
|
|
33
|
%
|
|
|
735
|
|
|
|
18
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(3)
|
|
$
|
2,862
|
|
|
|
100
|
%
|
|
$
|
2,369
|
|
|
|
100
|
%
|
|
$
|
3,965
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids (NGL) Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
208
|
|
|
|
74
|
%
|
|
$
|
74
|
|
|
|
64
|
%
|
|
$
|
128
|
|
|
|
62
|
%
|
Canada
|
|
|
39
|
|
|
|
14
|
%
|
|
|
20
|
|
|
|
17
|
%
|
|
|
38
|
|
|
|
19
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
247
|
|
|
|
88
|
%
|
|
|
94
|
|
|
|
81
|
%
|
|
|
166
|
|
|
|
81
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt
|
|
|
2
|
|
|
|
1
|
%
|
|
|
|
|
|
|
0
|
%
|
|
|
|
|
|
|
0
|
%
|
Argentina
|
|
|
31
|
|
|
|
11
|
%
|
|
|
22
|
|
|
|
19
|
%
|
|
|
40
|
|
|
|
19
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
33
|
|
|
|
12
|
%
|
|
|
22
|
|
|
|
19
|
%
|
|
|
40
|
|
|
|
19
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
280
|
|
|
|
100
|
%
|
|
$
|
116
|
|
|
|
100
|
%
|
|
$
|
206
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil and Gas Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
4,300
|
|
|
|
35
|
%
|
|
$
|
3,050
|
|
|
|
36
|
%
|
|
$
|
5,083
|
|
|
|
41
|
%
|
Canada
|
|
|
1,074
|
|
|
|
9
|
%
|
|
|
877
|
|
|
|
10
|
%
|
|
|
1,651
|
|
|
|
14
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
5,374
|
|
|
|
44
|
%
|
|
|
3,927
|
|
|
|
46
|
%
|
|
|
6,734
|
|
|
|
55
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt
|
|
|
3,372
|
|
|
|
28
|
%
|
|
|
2,553
|
|
|
|
30
|
%
|
|
|
2,739
|
|
|
|
22
|
%
|
Australia
|
|
|
1,459
|
|
|
|
12
|
%
|
|
|
363
|
|
|
|
4
|
%
|
|
|
372
|
|
|
|
3
|
%
|
North Sea
|
|
|
1,606
|
|
|
|
13
|
%
|
|
|
1,369
|
|
|
|
16
|
%
|
|
|
2,103
|
|
|
|
17
|
%
|
Argentina
|
|
|
372
|
|
|
|
3
|
%
|
|
|
362
|
|
|
|
4
|
%
|
|
|
380
|
|
|
|
3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
6,809
|
|
|
|
56
|
%
|
|
|
4,647
|
|
|
|
54
|
%
|
|
|
5,594
|
|
|
|
45
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(1)
|
|
$
|
12,183
|
|
|
|
100
|
%
|
|
$
|
8,574
|
|
|
|
100
|
%
|
|
$
|
12,328
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Financial derivative hedging activities increased oil and gas
production revenues for 2010 and 2009 by $165.3 million and
$180.8 million, respectively, and decreased oil and gas
production revenues for 2008 by $458.7 million. |
43
|
|
|
(2) |
|
Financial derivative hedging activities decreased 2010 oil
revenues by $57.0 million, increased 2009 oil revenues by
$45.2 million and decreased 2008 oil revenues by
$450.8 million. |
|
(3) |
|
Financial derivative hedging activities increased natural gas
revenues for 2010 and 2009 by $222.3 million and
$135.6 million, respectively, and decreased natural gas
revenues for 2008 by $7.9 million. |
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
|
|
|
Increase
|
|
|
|
|
|
Increase
|
|
|
|
|
|
|
2010
|
|
|
(Decrease)
|
|
|
2009
|
|
|
(Decrease)
|
|
|
2008
|
|
|
Oil Volume b/d:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
96,576
|
|
|
|
+8
|
%
|
|
|
89,133
|
|
|
|
−1
|
%
|
|
|
89,797
|
|
Canada
|
|
|
14,581
|
|
|
|
−4
|
%
|
|
|
15,186
|
|
|
|
−11
|
%
|
|
|
17,154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
111,157
|
|
|
|
+7
|
%
|
|
|
104,319
|
|
|
|
−2
|
%
|
|
|
106,951
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt
|
|
|
99,122
|
|
|
|
+8
|
%
|
|
|
92,139
|
|
|
|
+38
|
%
|
|
|
66,753
|
|
Australia
|
|
|
45,908
|
|
|
|
+369
|
%
|
|
|
9,779
|
|
|
|
+19
|
%
|
|
|
8,249
|
|
North Sea
|
|
|
56,791
|
|
|
|
−7
|
%
|
|
|
60,984
|
|
|
|
+3
|
%
|
|
|
59,494
|
|
Argentina
|
|
|
9,956
|
|
|
|
−13
|
%
|
|
|
11,505
|
|
|
|
−7
|
%
|
|
|
12,409
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
211,777
|
|
|
|
+21
|
%
|
|
|
174,407
|
|
|
|
+19
|
%
|
|
|
146,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(1)
|
|
|
322,934
|
|
|
|
+16
|
%
|
|
|
278,726
|
|
|
|
+10
|
%
|
|
|
253,856
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volume Mcf/d:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
730,847
|
|
|
|
+10
|
%
|
|
|
666,084
|
|
|
|
−2
|
%
|
|
|
679,876
|
|
Canada
|
|
|
396,005
|
|
|
|
+10
|
%
|
|
|
359,235
|
|
|
|
+2
|
%
|
|
|
352,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
1,126,852
|
|
|
|
+10
|
%
|
|
|
1,025,319
|
|
|
|
−1
|
%
|
|
|
1,032,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt
|
|
|
374,858
|
|
|
|
+3
|
%
|
|
|
362,618
|
|
|
|
+38
|
%
|
|
|
263,711
|
|
Australia
|
|
|
199,729
|
|
|
|
+9
|
%
|
|
|
183,617
|
|
|
|
+49
|
%
|
|
|
123,003
|
|
North Sea
|
|
|
2,391
|
|
|
|
−12
|
%
|
|
|
2,703
|
|
|
|
+3
|
%
|
|
|
2,637
|
|
Argentina
|
|
|
184,830
|
|
|
|
0
|
%
|
|
|
184,557
|
|
|
|
−6
|
%
|
|
|
195,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
761,808
|
|
|
|
+4
|
%
|
|
|
733,495
|
|
|
|
+25
|
%
|
|
|
585,002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(2)
|
|
|
1,888,660
|
|
|
|
+7
|
%
|
|
|
1,758,814
|
|
|
|
+9
|
%
|
|
|
1,617,609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL Volume b/d:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
13,777
|
|
|
|
+125
|
%
|
|
|
6,136
|
|
|
|
+3
|
%
|
|
|
5,986
|
|
Canada
|
|
|
2,884
|
|
|
|
+38
|
%
|
|
|
2,089
|
|
|
|
+1
|
%
|
|
|
2,076
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
16,661
|
|
|
|
+103
|
%
|
|
|
8,225
|
|
|
|
+2
|
%
|
|
|
8,062
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt
|
|
|
82
|
|
|
|
N/A
|
|
|
|
|
|
|
|
N/A
|
|
|
|
|
|
Argentina
|
|
|
3,180
|
|
|
|
−2
|
%
|
|
|
3,241
|
|
|
|
+12
|
%
|
|
|
2,887
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
3,262
|
|
|
|
+1
|
%
|
|
|
3,241
|
|
|
|
+12
|
%
|
|
|
2,887
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
19,923
|
|
|
|
+74
|
%
|
|
|
11,466
|
|
|
|
+5
|
%
|
|
|
10,949
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BOE per day(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
232,161
|
|
|
|
+13
|
%
|
|
|
206,284
|
|
|
|
−1
|
%
|
|
|
209,097
|
|
Canada
|
|
|
83,466
|
|
|
|
+8
|
%
|
|
|
77,147
|
|
|
|
−1
|
%
|
|
|
78,018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
315,627
|
|
|
|
+11
|
%
|
|
|
283,431
|
|
|
|
−1
|
%
|
|
|
287,115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt
|
|
|
161,680
|
|
|
|
+6
|
%
|
|
|
152,575
|
|
|
|
+38
|
%
|
|
|
110,704
|
|
Australia
|
|
|
79,196
|
|
|
|
+96
|
%
|
|
|
40,382
|
|
|
|
+40
|
%
|
|
|
28,750
|
|
North Sea
|
|
|
57,190
|
|
|
|
−7
|
%
|
|
|
61,435
|
|
|
|
+3
|
%
|
|
|
59,934
|
|
Argentina
|
|
|
43,941
|
|
|
|
−3
|
%
|
|
|
45,505
|
|
|
|
−5
|
%
|
|
|
47,904
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
342,007
|
|
|
|
+14
|
%
|
|
|
299,897
|
|
|
|
+21
|
%
|
|
|
247,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
657,634
|
|
|
|
+13
|
%
|
|
|
583,328
|
|
|
|
+9
|
%
|
|
|
534,407
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Approximately 12 percent of 2010 oil production was subject
to financial derivative hedges, compared to 10 percent in
2009 and 19 percent in 2008. |
44
|
|
|
(2) |
|
Approximately 23 percent of 2010 gas production was subject
to financial derivative hedges, compared to nine percent in 2009
and 20 percent in 2008. |
|
(3) |
|
The table shows reserves on a boe basis in which natural gas is
converted to an equivalent barrel of oil based on a 6:1 energy
equivalent ratio. This ratio is not reflective of the current
price ratio between the two products. |
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
|
|
|
Increase
|
|
|
|
|
|
Increase
|
|
|
|
|
|
|
2010
|
|
|
(Decrease)
|
|
|
2009
|
|
|
(Decrease)
|
|
|
2008
|
|
|
Average Oil price Per barrel:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
76.13
|
|
|
|
+29
|
%
|
|
$
|
59.06
|
|
|
|
−29
|
%
|
|
$
|
83.70
|
|
Canada
|
|
|
72.83
|
|
|
|
+30
|
%
|
|
|
56.16
|
|
|
|
−40
|
%
|
|
|
93.53
|
|
North America
|
|
|
75.69
|
|
|
|
+29
|
%
|
|
|
58.64
|
|
|
|
−31
|
%
|
|
|
85.28
|
|
Egypt
|
|
|
79.45
|
|
|
|
+30
|
%
|
|
|
61.34
|
|
|
|
−33
|
%
|
|
|
91.37
|
|
Australia
|
|
|
77.32
|
|
|
|
+20
|
%
|
|
|
64.42
|
|
|
|
−30
|
%
|
|
|
91.78
|
|
North Sea
|
|
|
76.66
|
|
|
|
+26
|
%
|
|
|
60.91
|
|
|
|
−36
|
%
|
|
|
95.76
|
|
Argentina
|
|
|
57.47
|
|
|
|
+16
|
%
|
|
|
49.42
|
|
|
|
0
|
%
|
|
|
49.46
|
|
International
|
|
|
77.21
|
|
|
|
+27
|
%
|
|
|
60.58
|
|
|
|
−32
|
%
|
|
|
89.63
|
|
Total(1)
|
|
|
76.69
|
|
|
|
+28
|
%
|
|
|
59.85
|
|
|
|
−32
|
%
|
|
|
87.80
|
|
Average Natural Gas price Per Mcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
5.28
|
|
|
|
+22
|
%
|
|
$
|
4.34
|
|
|
|
−51
|
%
|
|
$
|
8.86
|
|
Canada
|
|
|
4.48
|
|
|
|
+7
|
%
|
|
|
4.17
|
|
|
|
−47
|
%
|
|
|
7.94
|
|
North America
|
|
|
5.00
|
|
|
|
+17
|
%
|
|
|
4.28
|
|
|
|
−50
|
%
|
|
|
8.55
|
|
Egypt
|
|
|
3.62
|
|
|
|
−2
|
%
|
|
|
3.70
|
|
|
|
−30
|
%
|
|
|
5.25
|
|
Australia
|
|
|
2.24
|
|
|
|
+13
|
%
|
|
|
1.99
|
|
|
|
−5
|
%
|
|
|
2.10
|
|
North Sea
|
|
|
18.64
|
|
|
|
+42
|
%
|
|
|
13.15
|
|
|
|
−30
|
%
|
|
|
18.78
|
|
Argentina
|
|
|
1.96
|
|
|
|
0
|
%
|
|
|
1.96
|
|
|
|
+22
|
%
|
|
|
1.61
|
|
International
|
|
|
2.90
|
|
|
|
+1
|
%
|
|
|
2.87
|
|
|
|
−16
|
%
|
|
|
3.43
|
|
Total(2)
|
|
|
4.15
|
|
|
|
+12
|
%
|
|
|
3.69
|
|
|
|
−45
|
%
|
|
|
6.70
|
|
Average NGL Price Per barrel:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
41.45
|
|
|
|
+26
|
%
|
|
$
|
33.02
|
|
|
|
−44
|
%
|
|
$
|
58.62
|
|
Canada
|
|
|
36.61
|
|
|
|
+43
|
%
|
|
|
25.54
|
|
|
|
−48
|
%
|
|
|
49.33
|
|
North America
|
|
|
40.62
|
|
|
|
+31
|
%
|
|
|
31.12
|
|
|
|
−45
|
%
|
|
|
56.23
|
|
Egypt
|
|
|
69.75
|
|
|
|
N/A
|
|
|
|
|
|
|
|
N/A
|
|
|
|
|
|
Argentina
|
|
|
27.08
|
|
|
|
+44
|
%
|
|
|
18.76
|
|
|
|
−50
|
%
|
|
|
37.83
|
|
International
|
|
|
28.15
|
|
|
|
+50
|
%
|
|
|
18.76
|
|
|
|
−50
|
%
|
|
|
37.83
|
|
Total
|
|
|
38.58
|
|
|
|
+40
|
%
|
|
|
27.63
|
|
|
|
−46
|
%
|
|
|
51.38
|
|
|
|
|
(1) |
|
Reflects
per-barrel
decrease of $.48 in 2010, an increase of $.44 in 2009 and a
reduction of $4.85 in 2008 from financial derivative hedging
activities. |
|
(2) |
|
Reflects
per-Mcf
increase of $.32 in 2010 and $.21 in 2009 and a reduction of
$.01 in 2008 from financial derivative hedging activities. |
Crude Oil
Prices
A substantial portion of our oil production is sold at
prevailing market prices, which fluctuate in response to many
factors that are outside of the Companys control. Prices
we received for crude oil in 2010 were 28 percent above
2009 with economies stabilizing or growing across the globe.
Apache uses financial instruments to manage a
45
portion of its exposure to fluctuations in crude oil prices,
particularly in North America. In 2010, 12 percent of our
oil production was subject to financial derivative hedges,
reducing revenues by $57 million. In 2009, 10 percent
of our oil production was hedged, increasing oil revenue by
$45 million. For the year-end status of our derivatives,
please see Note 3 Derivative Instruments and
Hedging Activities in the Notes to Consolidated Financial
Statements set forth in Part IV, Item 15 of this
Form 10-K.
While the market price received for crude oil varies among
geographic areas, crude oil tends to trade at a global price.
With the exception of Argentina, price movements for all types
and grades of crude oil generally move in the same direction. In
Australia, Apache continues to directly market all of our crude
oil production into Australian domestic and international
markets at prices indexed to Dated Brent benchmark crude oil
prices plus a premium, which are typically above NYMEX oil
prices. In Argentina, we currently sell our oil in the domestic
market. The Argentine government imposes a sliding-scale tax on
oil exports, which significantly influences prices domestic
buyers are willing to pay. Domestic oil prices are currently
indexed to a $42 per barrel base price, subject to quality
adjustments and local premiums, and producers realize a gradual
increase or decrease as market prices deviate from the base
price. In Tierra del Fuego, similar pricing formulas exist, but
producers retain a value-added tax collected from buyers,
effectively increasing price realizations by 21 percent.
Natural
Gas Prices
Natural gas, which currently has a limited global transportation
system, is subject to price variances based on local supply and
demand conditions. The majority of our gas sales contracts are
indexed to prevailing local market prices. Apache uses a variety
of fixed-price contracts and derivatives to manage our exposure
to fluctuations in natural gas prices, primarily in North
America. In 2010, 23 percent of our gas production was
subject to financial derivative hedges, increasing revenues by
$222 million. In 2009, nine percent of our gas production
was hedged, increasing gas revenue by $136 million. For the
year-end status of our derivatives, please see
Note 3 Derivative Instruments and Hedging
Activities in the Notes to Consolidated Financial Statements set
forth in Part IV, Item 15 of this
Form 10-K.
Apache primarily sells natural gas into the North American
market, where spot prices increased 17 percent compared to
2009, and various international markets, where our average
contracted prices rose just one percent from 2009. Our primary
markets include North America, Egypt, Australia and Argentina.
|
|
|
|
|
North America has a common market; most of our gas is sold on a
monthly or daily basis at either monthly or daily market prices.
|
|
|
|
In Egypt our gas is sold to EGPC, with a majority under an
industry pricing formula indexed to Dated Brent crude oil with a
maximum gas price of $2.65 per MMBtu. On up to
100 MMcf/d
of gross production, there is no price cap for our gas under a
legacy contract, which expires at the end of 2012. Overall, the
region averaged $3.62 per Mcf in 2010.
|
|
|
|
Australia has a local market with a limited number of buyers and
sellers resulting in mostly long-term, fixed-price contracts
that are periodically adjusted for changes in the local consumer
price index. Recent increases in demand and higher development
costs have increased the prices required from the local market
in order to support the development of new supplies. As a
result, market prices received on recent contracts, including
our Reindeer field, are substantially higher than historical
levels.
|
|
|
|
In Argentina we receive government-regulated pricing on a
substantial portion of our production. The volumes we are
required to sell at regulated prices are set by the government
and vary with seasonal factors and industry category. During
2010 we realized an average price of $1.20 per Mcf on
government-regulated sales. The majority of the remaining
volumes were sold at market-driven prices, which averaged $2.65
per Mcf in 2010. Our overall average realized price for 2010 was
$1.96 per Mcf, the same as our 2009 average realized price and
22 percent higher than 2008 average realized price ($1.61
per Mcf).
|
During 2010 Apache signed three Gas Plus contracts totaling
63 MMcf/d
of gross production from fields in the Neuquén and Rio
Negro Provinces. Gas Plus is a program instituted by the
Argentine government to encourage new gas supplies through the
development of tight sands and unconventional reserves. The
first contract, for
10 MMcf/d
at $4.10 per MMBtu, has been extended through 2011 for
11 MMcf/d at $4.10 per
46
MMbtu. Our other two Gas Plus contracts, for a total of
53 MMcf/d
at $5.00 per MMBtu, are projected to commence in the first
quarter of 2011. The gas supplying the Gas Plus program
contracts is required to come from wells drilled in the
projects approved fields and formations. We believe the
Gas Plus program, coupled with changing market conditions, point
to improving price realizations going forward.
For more specific information on marketing arrangements by
country, please refer to Part I, Items 1 and
2 Business and Properties of this
Form 10-K.
Crude Oil
Revenues
2010 vs. 2009 During 2010 crude oil revenues totaled
$9.0 billion, $2.9 billion higher than the 2009 total
of $6.1 billion, driven by a 16-percent increase in
worldwide production and a 28-percent increase in average
realized prices. Average daily production in 2010 was 322.9
Mb/d, with prices averaging $76.69 per barrel. Crude oil
represented 74 percent of our 2010 oil and gas production
revenues and 49 percent of our equivalent production,
compared to 71 and 48 percent, respectively, in the prior
year. Higher realized prices contributed $1.7 billion to
the increase in full-year revenues, while higher production
volumes added another $1.2 billion.
Worldwide oil production increased 44.2 Mb/d, driven by a 36.1
Mb/d increase in Australia on new production from the Van Gogh
and Pyrenees discoveries, which were brought online in the first
quarter of 2010. U.S. production increased eight percent,
or 7.4 Mb/d, with the Permian region up 4.4 Mb/d on properties
added from the BP acquisitions, the Mariner merger and drilling
and recompletion activity. The Gulf Coast region added 1.8 Mb/d
from properties acquired in the Devon acquisition, the Mariner
merger and drilling and recompletion activity. Central region
production increased 1.2 Mb/d on drilling and recompletion
activity. Gross production in Egypt increased 17 percent,
while net production was up only eight percent, a function of
the mechanics of our production-sharing contracts. Net
production increased 7.0 Mb/d on production gains in the
Shushan, Matruh and numerous other concessions. Additional
capacity at the Kalabsha oil processing facility, as well as
processing of condensate-rich gas through the Salam Gas Plant
allowed by the new Jade manifold, allowed for much of the
production gains. North Sea production decreased 4.2 Mb/d on
natural decline and downtime. Production in Argentina and Canada
declined 1.5 Mb/d and .6 Mb/d, respectively, on natural decline.
2009 vs. 2008 Crude oil accounted for
48 percent of our equivalent production and 71 percent
of oil and gas production revenues during 2009, compared to 48
and 66 percent, respectively, for 2008. Impacted by
dramatically lower oil prices realized during the global
financial crisis that began in late 2008, crude oil revenues for
2009 totaled $6.1 billion, $2.1 billion lower than the
prior year. A 32-percent decline in average realized prices
reduced revenues $2.6 billion, of which $528 million
was offset by the impact of 10 percent production growth.
Worldwide production increased 24.9 Mb/d despite curtailed
capital spending, which was 40 percent lower than 2008.
Egypts oil production increased 38 percent or 25.4
Mb/d on exploration successes in numerous concessions, most
notably East Bahariya Extension, South Umbarka, Matruh,
Northeast Abu Gharadig Extension and Khalda, waterflood projects
and increased condensate from additional Qasr gas flowing
through the new processing trains at the Salam Gas Plant.
Australias production was up 1.5 Mb/d, as production was
restored following completion of repairs at Varanus Island.
North Sea production increased 1.5 Mb/d on strong drilling
results, which offset the impact of unplanned downtime at the
Bravo Platform, which lowered 2009 average daily oil production
by 2.6 Mb/d. The Bravo Platform was down for most of the fourth
quarter for pipeline repairs. Production declined 2.0 Mb/d in
Canada, .9 Mb/d in Argentina and .7 Mb/d in the U.S., as natural
decline offset results from our curtailed 2009 drilling programs.
Natural
Gas Revenues
2010 vs. 2009 Natural gas revenues for 2010 of
$2.9 billion were $493 million higher than 2009 on a
12-percent increase in realized prices and a seven-percent
increase in production volumes. Realized prices in 2010 averaged
$4.15 per Mcf and the $.46 per Mcf increase added
$297 million to revenues. Worldwide production rose
130 MMcf/d,
adding another $197 million to revenues.
Worldwide gas production rose in all of our core gas-producing
regions. U.S. production was up
64.8 MMcf/d,
or 10 percent. Driven by new drilling, recompletion
activity and properties acquired from Devon and the Mariner
47
merger, Gulf Coast region production was up
38.2 MMcf/d.
Permian region production was up
20.1 MMcf/d,
primarily on volumes from properties acquired from BP. Central
region production was up
6.5 MMcf/d
as additional production from new drilling and recompletions
outpaced natural decline. An active drilling and completion
program at Horn River and additional volumes from properties
acquired from BP led Canada region production
36.8 MMcf/d
higher. Production in Australia was up
16.1 MMcf/d
on higher customer takes from our John Brookes field. In Egypt,
gross production was up 14 percent, while net production
rose only three percent, a function of our production-sharing
contracts. The
12.2 MMcf/d
increase in net production relative to 2009 was attributable to
several factors, including a successful drilling and
recompletion program on our Matruh concession, additional
volumes processed through the Obaiyed Gas Plant and a full year
of additional capacity provided by the completion of two new gas
trains at the Salam Gas Plant. Argentinas production was
up marginally as production from new drilling and recompletions
was mostly offset by natural decline.
2009 vs. 2008 Natural gas accounted for
50 percent of our equivalent production and 28 percent
of our oil and gas production revenues during 2009, compared to
50 and 32 percent, respectively, for 2008. Impacted by
dramatically lower gas prices realized during the global
financial crisis that began in late 2008, gas revenues for 2009
totaled $2.4 billion, down $1.6 billion from 2008. A
45-percent decline in average realized prices reduced revenues
$1.8 billion, partially offset by the $184 million
impact of a nine percent increase in production.
Worldwide production grew
141 MMcf/d,
driven by a
99 MMcf/d
increase in Egypts net production and a
61 MMcf/d
increase in Australia. Egypts gas production was up
38 percent on exploration successes at our Khalda and
Matruh concessions and additional plant and pipeline capacity.
Additional capacity provided by the combination of two new
processing trains at the Salam Gas Plant and completion of a
project to increase compression on the Northern Gas Pipeline
allowed previously discovered wells in our Khalda Concession
Qasr field to come online. Australias 49 percent
production increase was driven by production restorations
following completion of repairs to the Varanus Island facility.
Canadas gas production increased
6 MMcf/d
from drilling and recompletion activities and a lower effective
royalty rate, partially offset by natural decline. Argentine
production decreased
11 MMcf/d
on natural decline and lower capital spending levels.
U.S. daily production declined
14 MMcf/d.
Production in the Gulf Coast decreased
8 MMcf/d
as production shut-in for facility, rig and third-party downtime
repairs reduced the 2009 production by
30 MMcf/d,
which more than offset net production gains from drilling
results. Our Central regions production declined
6 MMcf/d
primarily a result of the regions curtailed drilling
program, which was deferred until service costs fell in line
with lower commodity prices. Most of the regions drilling
activity occurred in the second half of the year.
48
Operating
Expenses
The table below presents a comparison of our expenses on an
absolute dollar basis and an equivalent unit of production (boe)
basis. Our discussion may reference expenses on a boe basis, on
an absolute dollar basis or both, depending on relevance.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
(Per boe)
|
|
|
|
|
|
Depreciation, depletion and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas property and equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring
|
|
$
|
2,861
|
|
|
$
|
2,202
|
|
|
$
|
2,358
|
|
|
$
|
11.92
|
|
|
$
|
10.34
|
|
|
$
|
12.06
|
|
Additional
|
|
|
|
|
|
|
2,818
|
|
|
|
5,334
|
|
|
|
|
|
|
|
13.24
|
|
|
|
27.27
|
|
Other assets
|
|
|
222
|
|
|
|
193
|
|
|
|
158
|
|
|
|
.92
|
|
|
|
.91
|
|
|
|
.81
|
|
Asset retirement obligation accretion
|
|
|
111
|
|
|
|
105
|
|
|
|
101
|
|
|
|
.46
|
|
|
|
.49
|
|
|
|
.52
|
|
Lease operating expenses
|
|
|
2,032
|
|
|
|
1,662
|
|
|
|
1,910
|
|
|
|
8.47
|
|
|
|
7.81
|
|
|
|
9.76
|
|
Gathering and transportation
|
|
|
178
|
|
|
|
143
|
|
|
|
157
|
|
|
|
.73
|
|
|
|
.67
|
|
|
|
.80
|
|
Taxes other than income
|
|
|
690
|
|
|
|
580
|
|
|
|
985
|
|
|
|
2.88
|
|
|
|
2.72
|
|
|
|
5.03
|
|
General and administrative expenses
|
|
|
380
|
|
|
|
344
|
|
|
|
289
|
|
|
|
1.58
|
|
|
|
1.62
|
|
|
|
1.48
|
|
Merger, acquisitions & transition
|
|
|
183
|
|
|
|
|
|
|
|
|
|
|
|
.77
|
|
|
|
|
|
|
|
|
|
Financing costs, net
|
|
|
229
|
|
|
|
242
|
|
|
|
166
|
|
|
|
.95
|
|
|
|
1.13
|
|
|
|
.85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,886
|
|
|
$
|
8,289
|
|
|
$
|
11,458
|
|
|
$
|
28.68
|
|
|
$
|
38.93
|
|
|
$
|
58.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
Depletion and Amortization
The following table details the changes in recurring
depreciation, depletion and amortization (DD&A) of oil and
gas properties between 2010 and 2008:
|
|
|
|
|
|
|
Recurring DD&A
|
|
|
|
(In millions)
|
|
|
2008
|
|
$
|
2,358
|
|
Volume change
|
|
|
150
|
|
Rate change
|
|
|
(306
|
)
|
|
|
|
|
|
2009
|
|
$
|
2,202
|
|
Volume change
|
|
|
317
|
|
Rate change
|
|
|
342
|
|
|
|
|
|
|
2010
|
|
$
|
2,861
|
|
|
|
|
|
|
2010 vs. 2009 Recurring full-cost depletion
expense increased $659 million on an absolute dollar basis:
$342 million on higher rate and $317 million from
additional production. Our full-cost depletion rate increased
$1.58 to $11.92 per boe as costs to acquire, find and develop
reserves exceeded our historical cost basis.
2009 vs. 2008 Recurring full-cost depletion
expense decreased $156 million on an absolute dollar basis:
$306 million on lower rate, partially offset by an increase
of $150 million from higher production. Our full-cost
depletion rate decreased $1.72 to $10.34 per boe. The decrease
in rate was driven by a $5.33 billion non-cash write-down
of the carrying value of our December 31, 2008, proved
property balances in the U.S., U.K. North Sea, Canada and
Argentina and a $2.82 billion non-cash write-down of the
carrying value of our March 31, 2009, proved oil and gas
property balances in the U.S. and Canada. The impact of the
write-downs was partially offset by 2009 drilling and finding
costs, which exceeded our historical cost basis.
49
Lease
Operating Expenses
Lease operating expenses (LOE) include several components:
direct operating costs, repair and maintenance, and workover
costs.
Direct operating costs generally trend with commodity prices and
are impacted by the type of commodity produced and the location
of properties (i.e., offshore, onshore, remote locations, etc.).
Fluctuations in commodity prices impact operating cost elements
both directly and indirectly. They directly impact costs such as
power, fuel, and chemicals, which are commodity-price based.
Commodity prices also affect industry activity and demand, thus
indirectly impacting the cost of items such as labor, boats,
helicopters, materials and supplies. Oil, which contributed
nearly half of our production, is inherently more expensive to
produce than natural gas. Repair and maintenance costs are
typically higher on offshore properties and in areas with remote
plants and facilities. All production in Australia and the North
Sea and nearly 90 percent from the U.S. Gulf Coast
region comes from offshore properties. Workovers accelerate
production; hence, activity generally increases with higher
commodity prices. Foreign exchange rate fluctuations generally
impact the Companys LOE, with a weakening U.S. dollar
adding to
per-unit
costs and a strengthening U.S. dollar lowering
per-unit
costs in our international regions.
2010 vs. 2009 Our 2010 LOE increased $370 million
from 2009, or 22 percent on an absolute dollar basis. On a
per-unit
basis, LOE increased eight percent with a 22 percent
increase on higher costs, offset by a 14 percent decline
related to increased production. The rate was impacted by the
items below:
|
|
|
|
|
|
|
Per boe
|
|
|
2009 LOE
|
|
$
|
7.81
|
|
Acquisitions, net of associated production
|
|
|
.27
|
|
Foreign exchange rate impact
|
|
|
.22
|
|
Equipment rental
|
|
|
.22
|
|
Workover costs
|
|
|
.16
|
|
Stock-based compensation
|
|
|
.14
|
|
Labor and pumper costs
|
|
|
.08
|
|
Material
|
|
|
.07
|
|
Power and fuel
|
|
|
.07
|
|
Incentive compensation
|
|
|
.05
|
|
Other
|
|
|
.15
|
|
Other increased production
|
|
|
(.77
|
)
|
|
|
|
|
|
2010 LOE
|
|
$
|
8.47
|
|
|
|
|
|
|
2009 vs. 2008 Our 2009 LOE decreased $248 million
from 2008. LOE per boe was down 20 percent: 13 percent
on lower cost and seven percent on higher production. The rate
was impacted by the items below:
|
|
|
|
|
|
|
Per boe
|
|
|
2008 LOE
|
|
$
|
9.76
|
|
Higher production
|
|
|
(.68
|
)
|
Workover costs
|
|
|
(.36
|
)
|
Foreign exchange rate impact
|
|
|
(.33
|
)
|
Power and fuel
|
|
|
(.32
|
)
|
Labor and pumper costs
|
|
|
(.10
|
)
|
Hurricane repairs
|
|
|
(.10
|
)
|
Other
|
|
|
(.06
|
)
|
|
|
|
|
|
2009 LOE
|
|
$
|
7.81
|
|
|
|
|
|
|
50
Gathering
and Transportation
We generally sell oil and natural gas under two common types of
agreements, both of which include a transportation charge. One
is a netback arrangement, under which we sell oil or natural gas
at the wellhead and collect a lower relative price to reflect
transportation costs to be incurred by the purchaser. In this
case, we record sales at the netback price received from the
purchaser. Alternatively, we sell oil or natural gas at a
specific delivery point, pay our own transportation to a
third-party carrier and receive a price with no transportation
deduction. In this case we record the separate transportation
cost as gathering and transportation costs.
In the U.S., Canada and Argentina, we sell oil and natural gas
under both types of arrangements. In the North Sea, we pay
transportation charges to a third-party carrier. In Australia,
oil and natural gas are sold under netback arrangements. In
Egypt, our oil and natural gas production is primarily sold to
EGPC under netback arrangements; however, we also export crude
oil under both types of arrangements.
The following table presents gathering and transportation costs
we paid directly to third-party carriers for each of the periods
presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
U.S.
|
|
$
|
42
|
|
|
$
|
36
|
|
|
$
|
40
|
|
Canada
|
|
|
75
|
|
|
|
53
|
|
|
|
63
|
|
North Sea
|
|
|
25
|
|
|
|
26
|
|
|
|
28
|
|
Egypt
|
|
|
31
|
|
|
|
23
|
|
|
|
21
|
|
Argentina
|
|
|
5
|
|
|
|
5
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gathering and Transportation
|
|
$
|
178
|
|
|
$
|
143
|
|
|
$
|
157
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 vs. 2009 Gathering and transportation
costs increased $35 million from 2009. The increase in the
U.S. resulted from an increase in both the volumes
transported under arrangements where we pay costs directly to
third parties and in rates. The increase in Canada resulted from
an increase in volumes, rate and foreign exchange rates. North
Sea costs were down on lower production and foreign exchange
rates. Egypt costs increased as a result of higher shipping,
handling and pipeline fees as compared to the prior year.
2009 vs. 2008 Gathering and transportation
costs decreased $14 million from 2008. The decreases in the
U.S. and Canada resulted from a decrease in both the
volumes transported under arrangements where we pay costs
directly to third parties and in rates. North Sea costs were
down on foreign exchange rates. Egypt costs increased as a
result of retroactive terminal fees claimed by EGPC, partially
offset by a decrease in export cargoes as more crude oil was
purchased by EGPC for domestic use in the latter part of 2009.
Taxes
Other Than Income
Taxes other than income primarily comprises U.K. Petroleum
Revenue Tax (PRT), severance taxes on properties onshore and in
state or provincial waters off the coast of the U.S. and
Australia and ad valorem taxes on properties in the
U.S. and Canada. Severance taxes are generally based on a
percentage of oil and gas production revenues, while the U.K.
PRT is assessed on net receipts (revenues less qualifying
operating costs and capital spending) from the Forties field in
the U.K. North Sea. We are subject to a variety of other taxes
including U.S. franchise taxes, Australian Petroleum
Resources Rent tax and various Canadian taxes including:
Freehold
51
Mineral tax, Saskatchewan Capital tax and Saskatchewan Resources
surtax. We also pay taxes on invoices and bank transactions in
Argentina. The table below presents a comparison of these
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
U.K. PRT
|
|
$
|
422
|
|
|
$
|
383
|
|
|
$
|
695
|
|
Severance taxes
|
|
|
142
|
|
|
|
88
|
|
|
|
168
|
|
Ad valorem taxes
|
|
|
80
|
|
|
|
55
|
|
|
|
71
|
|
Other taxes
|
|
|
46
|
|
|
|
54
|
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Taxes other than income
|
|
$
|
690
|
|
|
$
|
580
|
|
|
$
|
985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 vs. 2009 Taxes other than income were
$110 million higher than 2009. U.K. PRT was
$39 million more than 2009 on a 10 percent increase in
net profits driven by higher oil revenues. Severance taxes
increased $54 million from higher taxable revenues in the
U.S., predominantly resulting from acquisitions, and consistent
with higher realized oil and natural gas prices relative to the
prior year. The $25 million increase in ad valorem taxes
resulted from higher taxable valuations in the
U.S. associated with increases in oil and natural gas
prices relative to the prior year and the BP and Devon
acquisitions and Mariner merger.
2009 vs. 2008 Taxes other than income were
$405 million lower than 2008. U.K. PRT was
$312 million less than 2008 on a 43 percent decrease
in net profits, driven by lower oil revenues and lower operating
and capital costs. The decrease in severance taxes resulted from
lower taxable revenues in the U.S., consistent with the lower
realized oil and natural gas prices relative to the prior year.
The $16 million decrease in ad valorem taxes resulted from
lower taxable valuations associated with decreases in oil and
natural gas prices.
General
and Administrative Expenses
2010 vs. 2009 General and administrative
(G&A) expenses were $36 million higher in 2010 than in
2009. On a per boe basis, G&A expenses decreased two
percent as the effect of higher volumes more than offset the
increase in costs. G&A expense was impacted by the
following:
|
|
|
|
|
2009 G&A
|
|
$
|
1.62
|
|
Workforce reduction costs
|
|
|
(.19
|
)
|
Stock-based compensation
|
|
|
.15
|
|
Other incentive compensation
|
|
|
.06
|
|
Kitimat LNG administrative costs
|
|
|
.03
|
|
Other corporate costs
|
|
|
.11
|
|
Increased production
|
|
|
(.20
|
)
|
|
|
|
|
|
2010 G&A
|
|
$
|
1.58
|
|
|
|
|
|
|
2009 vs. 2008 G&A expenses were
$55 million higher in 2009 than in 2008. On a per boe
basis, G&A expenses increased nine percent: 19 percent
on higher costs, offset by a 10 percent reduction on higher
volumes. G&A expense was impacted by the following:
|
|
|
|
|
2008 G&A
|
|
$
|
1.48
|
|
Workforce reduction costs
|
|
|
.20
|
|
Stock-based compensation
|
|
|
.17
|
|
Other incentive compensation
|
|
|
(.06
|
)
|
Other corporate costs
|
|
|
(.03
|
)
|
Increased production
|
|
|
(.14
|
)
|
|
|
|
|
|
2009 G&A
|
|
$
|
1.62
|
|
|
|
|
|
|
52
Merger,
Acquisitions & Transition
In 2010, the Company recognized $183 million in merger,
acquisitions & transition costs related to our BP and
Devon acquisitions and the Mariner merger. A summary of these
costs follows:
|
|
|
|
|
Separation and retention costs
|
|
$
|
114
|
|
Investment banking fees
|
|
|
42
|
|
Other costs
|
|
|
27
|
|
|
|
|
|
|
2010 Merger, Acquisitions & Transition
|
|
$
|
183
|
|
|
|
|
|
|
Merger, acquisitions & transition costs during 2008
and 2009 were not material.
Financing
Costs, Net
Financing costs incurred during the periods noted are composed
of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Interest expense
|
|
$
|
345
|
|
|
$
|
309
|
|
|
$
|
280
|
|
Amortization of deferred loan costs
|
|
|
17
|
|
|
|
6
|
|
|
|
4
|
|
Capitalized interest
|
|
|
(120
|
)
|
|
|
(61
|
)
|
|
|
(94
|
)
|
Interest income
|
|
|
(13
|
)
|
|
|
(12
|
)
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financing costs, net
|
|
$
|
229
|
|
|
$
|
242
|
|
|
$
|
166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 vs. 2009 Financing costs, net decreased
$13 million from 2009. The decrease is primarily related to
a $59 million increase in capitalized interest, the result
of additional unproved balances from the BP acquisitions and
Mariner merger. This decrease is partially offset by a
$36 million increase in interest expense from three debt
issuances in 2010 and $11 million higher amortization of
deferred loan costs related to the new debt and repayment of the
Australian project financing facility.
2009 vs. 2008 Financing costs, net increased
$76 million from 2008. The increase in cost is primarily
the result of a $29 million increase in interest expense
related to higher average outstanding debt balances, a
$33 million reduction in capitalized interest related to
lower unproved property balances and completion of several
long-term construction projects, and a $12 million decrease
in interest income on a lower average cash balance and lower
interest rates.
Provision
for Income Taxes
2010 vs. 2009 The provision for income taxes
totaled $2.2 billion in 2010 compared to $611 million
in 2009. The effective rates for 2010 and 2009 were skewed by
the effect of currency exchange rates on our foreign deferred
tax liabilities and other net tax settlements. Total taxes and
the effective rate for 2009 were also impacted by the magnitude
of the taxes related to the full-cost write-down in that year.
Excluding these items, the 2010 and 2009 effective tax rates
were comparable at 40.75 percent and 39.75 percent,
respectively.
2009 vs. 2008 The provision for income taxes
totaled $611 million in 2009 compared to $220 million
in 2008. Total taxes and the effective rates for each period
were skewed by the magnitude of the taxes related to the 2009
and 2008 full-cost write-downs, the effect of currency exchange
rates on our foreign deferred tax liabilities and other net tax
settlements. Excluding these items, the 2009 and 2008 effective
tax rates were comparable at 39.75 percent and
39.58 percent, respectively.
Non-GAAP Measures
The Company makes reference to some measures in discussion of
its financial and operating highlights that are not required by
or presented in accordance with GAAP. Management uses these
measures in assessing operating
53
results and believes the presentation of these measures provides
information useful in assessing the Companys financial
condition and results of operations. These non-GAAP measures
should not be considered as alternatives to GAAP measures and
may be calculated differently from, and therefore may not be
comparable to, similarly-titled measures used at other companies.
Adjusted
Earnings
To assess the Companys operating trends and performance,
management uses Adjusted Earnings, which is net income excluding
certain items that management believes affect the comparability
of operating results. Management believes this presentation may
be useful to investors who follow the practice of some industry
analysts who adjust reported company earnings for items that may
obscure underlying fundamentals and trends. The reconciling
items below are the types of items management excludes and
believes are frequently excluded by analysts when evaluating the
operating trends and comparability of the Companys results.
|
|
|
|
|
|
|
|
|
|
|
For the Year
|
|
|
|
Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In millions, except share data)
|
|
|
Income (Loss) Attributable to Common Stock (GAAP)
|
|
$
|
3,000
|
|
|
$
|
(292
|
)
|
Adjustments:
|
|
|
|
|
|
|
|
|
Foreign currency fluctuation impact on deferred tax expense
|
|
|
52
|
|
|
|
198
|
|
Merger, acquisitions & transition, net of tax(1)
|
|
|
120
|
|
|
|
|
|
Additional depletion, net of tax(2)
|
|
|
|
|
|
|
1,981
|
|
|
|
|
|
|
|
|
|
|
Adjusted Earnings (Non-GAAP)
|
|
$
|
3,172
|
|
|
$
|
1,887
|
|
|
|
|
|
|
|
|
|
|
Adjusted Earnings Per Share (Non-GAAP)
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
9.02
|
|
|
$
|
5.62
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
8.94
|
|
|
$
|
5.59
|
|
|
|
|
|
|
|
|
|
|
Average Number of Common Shares
|
|
|
|
|
|
|
|
|
Basic
|
|
|
352
|
|
|
|
336
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
359
|
|
|
|
338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Merger, acquisitions & transition costs recorded in
2010 totaled $183 million pre-tax, for which a tax benefit
of $63 million was recognized. The tax effect was
calculated utilizing the statutory rates in effect in each
country where costs were incurred. |
|
(2) |
|
Additional depletion (non-cash write-down of the carrying value
of proved property) recorded in 2009 was $2.82 billion
pre-tax, for which a deferred tax benefit of $837 million
was recognized. The tax effect of the write-down of the carrying
value of proved property (additional depletion) in 2009 was
calculated utilizing the statutory rates in effect in each
country where a write-down occurred. |
Acquisitions
and Divestitures
2010
Activity
In the fourth quarter of 2010 Apache acquired Mariner, an
independent exploration and production company, in a stock and
cash transaction totaling $2.7 billion. We also assumed
approximately $1.7 billion of Mariners debt in
connection with the merger. The transaction was accounted for as
a business combination, with Mariners assets and
liabilities reflected in Apaches financial statements at
fair value. Mariners oil and gas properties are primarily
located in the Gulf of Mexico deepwater and shelf, the Permian
Basin and onshore in the Gulf Coast. The Permian Basin and Gulf
of Mexico shelf assets are complementary to Apaches
existing holdings and provide an inventory of future potential
drilling locations, particularly in the Spraberry and Wolfcamp
formation oil plays of the Permian Basin. Additionally, Mariner
has accumulated acreage in emerging unconventional shale oil
resources in the U.S.
54
In the third and fourth quarters of 2010 Apache completed the
acquisition of BPs oil and gas operations, related
infrastructure and acreage in the Permian Basin of west Texas
and New Mexico, substantially all of BPs Western Canadian
upstream natural gas assets and BPs interests in four
development licenses and one exploration concession (East Badr
El Din) in the Western Desert of Egypt. The aggregate purchase
price of the BP acquisitions, subsequent to exercise of
preferential purchase rights, was $6.4 billion, subject to
normal post-closing adjustments. The effective date of these
acquisitions was July 1, 2010.
In the second quarter of 2010 Apache completed an acquisition of
oil and gas assets on the Gulf of Mexico shelf from Devon for
$1.05 billion, subject to normal post-closing adjustments.
The acquisition from Devon was effective January 1, 2010,
and included 477,000 acres across 150 blocks.
During the first quarter of 2010 Apache Canada, through its
subsidiaries, closed the acquisition of a 51-percent interest in
the Kitimat LNG facility and a 25.5-percent interest in a
partnership that owns a related proposed pipeline. EOG Resources
Canada owns the remaining 49 percent of the Kitimat LNG
facility and a 24.5-percent interest in the pipeline
partnership. In February 2011 Apache Canada and EOG Canada
entered into an agreement to purchase the remaining 50-percent
interest in the partnership. Upon close of the transaction,
Apache Canada and EOG Canada will own 51 percent and
49 percent, respectively, of the pipeline partnership and
proposed pipeline.
For further information regarding these acquisitions, please see
Note 2 Acquisitions in the Notes to
Consolidated Financial Statements set forth in Part IV,
Item 15 of this
Form 10-K.
2009
Activity
During the second quarter of 2009 Apache announced the
acquisition of nine Permian Basin oil and gas fields with
then-current net production of 3,500 boe/d from Marathon Oil
Corporation for $187.4 million, subject to normal
post-closing adjustments. Estimated reserves acquired in
connection with the acquisition totaled 19.5 MMboe. These
long-lived fields fit well with Apaches existing
properties in the Permian Basin, particularly in Lea County, New
Mexico, and will provide the Company many years of drilling
opportunities. The effective date of the transaction was
January 1, 2009.
2008
Activity
There was no major acquisition activity during 2008; however,
the Company completed several divestiture transactions. On
January 29, 2008, the Company completed the sale of its
interest in Ship Shoal blocks 349 and 359 on the outer
continental shelf of the Gulf of Mexico to W&T Offshore,
Inc. for $116 million. On January 31, 2008, the
Company completed the sale of non-strategic oil and gas
properties in the Permian Basin of West Texas to Vanguard
Permian, LLC for $78 million. On April 2, 2008, the
Company completed the sale of non-strategic Canadian properties
to Central Global Resources for C$112 million.
Capital
Resources and Liquidity
Operating cash flows is a primary source of liquidity.
Apaches cash flows, both in the short-term and the
long-term, are impacted by highly volatile oil and natural gas
prices. Significant deterioration in commodity prices negatively
impacts revenues, earnings and cash flows, capital spending and
potentially our liquidity if spending does not trend downward as
well. Sales volumes and costs also impact cash flows; however,
these historically have not been as volatile or as impactive as
commodity prices in the short-term.
Apaches long-term operating cash flows are dependent on
reserve replacement and the level of costs required for ongoing
operations. Our business, as with other extractive industries,
is a depleting one in which each barrel produced must be
replaced or the Company and its reserves, a critical source of
future liquidity, will shrink. Cash investments are required
continuously to fund exploration and development projects and
acquisitions, which are necessary to offset the inherent
declines in production and proven reserves. Future success in
maintaining and growing reserves and production is highly
dependent on the success of our exploration and development
activities or our ability to acquire additional reserves at
reasonable costs. For a discussion of risk factors related to
our business and operations, please see Part I,
Item 1A Risk Factors.
55
We may also elect to utilize available committed borrowing
capacity, access to both debt and equity capital markets, or
proceeds from the occasional sale of nonstrategic assets for all
other liquidity and capital resource needs. Apaches
ability to access the debt and equity capital markets is
supported by its investment-grade credit ratings.
We believe the liquidity and capital resource alternatives
available to Apache, combined with internally-generated cash
flows, will be adequate to fund short-term and long-term
operations, including our capital spending program, repayment of
debt maturities and any amount that may ultimately be paid in
connection with contingencies.
Apaches primary uses of cash are exploration, development
and acquisition of oil and gas properties, costs necessary to
maintain ongoing operations, repayment of principal and interest
on outstanding debt and payment of dividends. We fund our
exploration and development activities primarily through
operating cash flows and budget capital expenditures based on
projected cash flows.
See additional information, please see Part I, Items 1
and 2 Business and Properties and Part I,
Item 1A Risk Factors of this
Form 10-K.
56
Sources
and Uses of Cash
The following table presents the sources and uses of our cash
and cash equivalents for the years presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Sources of Cash and Cash Equivalents:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
6,726
|
|
|
$
|
4,224
|
|
|
$
|
7,065
|
|
Net commercial paper and bank loan borrowings
|
|
|
318
|
|
|
|
|
|
|
|
|
|
Sale of short-term investments
|
|
|
|
|
|
|
792
|
|
|
|
|
|
Sales of property and equipment
|
|
|
|
|
|
|
2
|
|
|
|
308
|
|
Project financing draw-downs
|
|
|
|
|
|
|
250
|
|
|
|
100
|
|
Fixed-rate debt borrowings
|
|
|
2,470
|
|
|
|
|
|
|
|
796
|
|
Proceeds from issuance of common stock
|
|
|
2,258
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of depositary shares
|
|
|
1,227
|
|
|
|
|
|
|
|
|
|
Common stock activity
|
|
|
70
|
|
|
|
29
|
|
|
|
32
|
|
Treasury stock activity
|
|
|
9
|
|
|
|
6
|
|
|
|
4
|
|
Other
|
|
|
27
|
|
|
|
29
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,105
|
|
|
|
5,332
|
|
|
|
8,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Uses of Cash and Cash Equivalents:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures(1)
|
|
|
4,922
|
|
|
|
3,631
|
|
|
|
5,823
|
|
Purchase of short-term investments
|
|
|
|
|
|
|
|
|
|
|
792
|
|
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Devon properties
|
|
|
1,018
|
|
|
|
|
|
|
|
|
|
BP properties
|
|
|
6,429
|
|
|
|
|
|
|
|
|
|
Mariner
|
|
|
787
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
126
|
|
|
|
310
|
|
|
|
150
|
|
Net commercial paper and bank loan repayments
|
|
|
|
|
|
|
2
|
|
|
|
200
|
|
Project financing repayment
|
|
|
350
|
|
|
|
|
|
|
|
|
|
Payments on fixed-rate notes
|
|
|
1,023
|
|
|
|
100
|
|
|
|
|
|
Redemption of preferred stock
|
|
|
|
|
|
|
98
|
|
|
|
|
|
Dividends
|
|
|
226
|
|
|
|
209
|
|
|
|
239
|
|
Cost of debt and equity transactions
|
|
|
17
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
121
|
|
|
|
115
|
|
|
|
85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,019
|
|
|
|
4,465
|
|
|
|
7,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
|
$
|
(1,914
|
)
|
|
$
|
867
|
|
|
$
|
1,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The table presents capital expenditures on a cash basis;
therefore, the amounts differ from those discussed elsewhere in
this document, which include accruals. |
Net Cash
Provided by Operating Activities
Operating cash flows is our primary source of capital and
liquidity and is impacted, both in the short-term and the
long-term, by highly volatile oil and natural gas prices.
Apaches average natural gas price realizations fluctuated
throughout 2010, dipping from a high of $4.84 per Mcf in
February to a low of $3.89 in September before increasing to
$4.19 in December. Average realized natural gas prices for the
year rose 12 percent over 2009 to $4.15 per Mcf. Our
average crude oil realizations saw an
57
increase throughout the year from a low of $70.68 per barrel in
May 2010, peaking in December at $86.01 per barrel. Crude oil
prices averaged $76.69 per barrel for 2010, up 28 percent
from 2009.
In order to manage the variability in cash flows, we utilize
commodity hedges. At the end of 2010, we had hedged an average
of just over 375,000 MMBtu per day of our 2011 North
American natural gas production. The volumes were primarily
hedged using fixed-price swaps at an average price of
approximately $6.25 per MMBtu. For perspective, the natural gas
hedges represent 24 percent of fourth-quarter 2010 North
America daily gas production and 16 percent worldwide.
For liquids, we had an average of just under 98,000 b/d of oil
production hedged for 2011. Crude oil production was primarily
hedged using collars that had average floor and ceiling prices
of approximately $69 and $97 per barrel, respectively. In
addition, 20,000 b/d of our North Sea Forties field production
will be sold under a physical delivery contract subject to a
minimum price of $70 a barrel and a ceiling price of $99 a
barrel. For perspective, the combined 2011 financial derivatives
represent approximately 35 percent of fourth-quarter 2010
worldwide daily oil production.
For additional information regarding our derivative contracts,
please see Note 3 Derivative Instruments and
Hedging Activities in the Notes to Consolidated Financial
Statements set forth in Part IV, Item 15 of this
Form 10-K.
For quantitative and qualitative information regarding our use
of derivatives to manage commodity price risk, please see
Commodity Risk in Part II, Item 7A of this
Form 10-K.
The factors affecting operating cash flows are largely the same
as those that affect net earnings, with the exception of
non-cash expenses such as DD&A, asset retirement obligation
(ARO) accretion and deferred income tax expense, which affect
earnings but do not affect cash flows.
For 2010, operating cash flows totaled $6.7 billion, up
$2.5 billion from 2009. The primary driver of the increase
was a $3.6 billion increase in oil and gas revenues on both
higher production and prices, especially oil. This was partially
offset by higher cash-based expenses, including merger and
transition expenses associated with our acquisitions in 2010,
and higher income tax payments in 2010.
For a detailed discussion of commodity prices, production, costs
and expenses, please see Results of Operations in
this Item 7. For additional detail on the changes in
operating assets and liabilities and the non-cash expenses which
do not impact net cash provided by operating activities, please
see the Statement of Consolidated Cash Flows in the Consolidated
Financial Statements set forth in Part IV, Item 15 of
this
Form 10-K.
Commercial
Paper and Bank Loans
The Company has available a $2.95 billion commercial paper
program, which generally enables Apache to borrow funds for up
to 270 days at competitive interest rates. As of
December 31, 2010, the Company had $913 million in
commercial paper outstanding. For further discussion of our
commercial paper program, please see Liquidity below
and Note 5 Debt in the Notes to Consolidated
Financial Statements set forth in Part IV, Item 15 of
this
Form 10-K.
Upon consummation of our merger with Mariner, we assumed credit
lines with outstanding borrowings of approximately
$632 million. Commercial paper was issued to repay this
amount, and credit lines assumed from Mariner were terminated
prior to year-end 2010.
Short-term
Investments
We occasionally invest in highly-liquid, short-term investments
until funds are needed to further supplement our operating cash
flows. At December 31, 2008, we had $792 million
invested in U.S. Treasury securities with original
maturities greater than three months but less than one year.
These securities matured on April 2, 2009. None were held
at December 31, 2010 or 2009.
Project
Financing
One of the Companys Australian subsidiaries had a secured
revolving syndicated credit facility for its Van Gogh and
Pyrenees oil developments offshore Western Australia. The
outstanding balance under the facility was
58
$350 million at December 31, 2009. We paid off
$50 million of the facility in June 2010 and the remaining
balance in December 2010. For a more detailed discussion of this
facility and information regarding our available committed
borrowing capacity, please see Liquidity below.
Fixed-Rate
Debt
On August 20, 2010, the Company issued $1.5 billion
principal amount of senior unsecured 5.1-percent notes maturing
September 1, 2040. The notes are redeemable, as a whole or
in part, at Apaches option, subject to a make-whole
premium. The proceeds were used to repay borrowings under a
bridge facility and the Companys commercial paper program
that were used to finance the BP acquisitions.
On December 3, 2010, the Company issued $500 million
principal amount of senior unsecured 3.625-percent notes
maturing February 1, 2021, and $500 million principal
amount of senior unsecured 5.25-percent notes maturing
February 1, 2042. The notes are redeemable, as a whole or
in part, at Apaches option, subject to a make-whole
premium. The proceeds were used to redeem the outstanding public
debt of $1.0 billion assumed upon completion of
Apaches acquisition of Mariner on November 10, 2010.
Proceeds
from Issuance of Common Stock
On July 28, 2010, in conjunction with Apaches
$6.4 billion acquisition of properties from BP, the Company
issued 26.45 million shares of common stock at a public
offering price of $88 per share. Proceeds, after underwriting
discounts and before expenses, from the common stock offering
totaled approximately $2.3 billion.
Proceeds
from Issuance of Mandatory Convertible Preferred Stock
On July 28, 2010, Apache issued 25.3 million
depositary shares, each representing a 1/20th interest in a
share of Apaches 6.00-percent Mandatory Convertible
Preferred Stock, Series D, with an initial liquidation
preference of $1,000 per share (equivalent to $50 liquidation
preference per depositary share). The Company received proceeds
of approximately $1.2 billion, after underwriting discounts
and before expenses, from the sale.
Capital
Expenditures
We fund exploration and development activities primarily through
operating cash flows and budget capital expenditures based on
projected operating cash flows. Our operating cash flows, both
in the short and long term, are impacted by highly volatile oil
and natural gas prices, production levels, industry trends
impacting operating expenses and our ability to continue to
acquire or find high-margin reserves at competitive prices. For
these reasons, operating cash flow forecasts are revised monthly
in response to changing market conditions and production
projections. Apache routinely adjusts capital expenditure
budgets in response to these adjusted operating cash flow
forecasts and market trends in drilling and acquisitions costs.
Historically, we have used a combination of operating cash
flows, borrowings under lines of credit and commercial paper
program and, from time to time, issues of public debt or common
stock to fund significant acquisitions.
59
The following table details capital expenditures for each
country in which we do business.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Exploration and Development:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
1,623
|
|
|
$
|
929
|
|
|
$
|
2,183
|
|
Canada
|
|
|
860
|
|
|
|
412
|
|
|
|
705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America
|
|
|
2,483
|
|
|
|
1,341
|
|
|
|
2,888
|
|
Egypt
|
|
|
757
|
|
|
|
676
|
|
|
|
853
|
|
Australia
|
|
|
624
|
|
|
|
602
|
|
|
|
880
|
|
North Sea
|
|
|
617
|
|
|
|
375
|
|
|
|
459
|
|
Argentina
|
|
|
240
|
|
|
|
140
|
|
|
|
318
|
|
Chile
|
|
|
20
|
|
|
|
11
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
|
2,258
|
|
|
|
1,804
|
|
|
|
2,537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Worldwide Exploration and Development Costs
|
|
|
4,741
|
|
|
|
3,145
|
|
|
|
5,425
|
|
Gathering, Transmission and Processing Facilities (GTP):
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
159
|
|
|
|
83
|
|
|
|
29
|
|
Egypt
|
|
|
182
|
|
|
|
151
|
|
|
|
571
|
|
Australia
|
|
|
162
|
|
|
|
69
|
|
|
|
54
|
|
Argentina
|
|
|
3
|
|
|
|
2
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total GTP Costs
|
|
|
506
|
|
|
|
305
|
|
|
|
659
|
|
Asset Retirement Costs
|
|
|
459
|
|
|
|
288
|
|
|
|
514
|
|
Capitalized Interest
|
|
|
120
|
|
|
|
61
|
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures, excluding Acquisitions
|
|
|
5,826
|
|
|
|
3,799
|
|
|
|
6,692
|
|
Acquisitions, including GTP
|
|
|
11,557
|
|
|
|
310
|
|
|
|
150
|
|
Asset Retirement Costs Acquired
|
|
|
847
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capital Expenditures
|
|
$
|
18,230
|
|
|
$
|
4,114
|
|
|
$
|
6,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Development As a result of
Apaches determination to not outspend our operating cash
flows, we curtailed 2009 capital expenditures in response to the
decline in commodity prices and financial uncertainty in the
global economy at the outset of 2009. Our 2010 drilling and
development budgets were increased in response to recovering
commodity prices and projected increases in operating cash
flows. As a result, worldwide E&D expenditures for 2010
were 51 percent higher than 2009.
E&D spending in North America, which was up 85 percent
from the prior year, totaled 52 percent of worldwide
E&D spending, up from 43 percent in 2009.
U.S. E&D expenditures were $694 million or
75 percent higher than year-ago levels on expanded drilling
activities in the Permian region and horizontal drilling in the
Granite Wash play in the Central region. Activity related to
newly acquired properties in the Permian and Gulf Coast regions
also contributed to increased E&D expenditures late in the
year. E&D spending in Canada more than doubled, increasing
to $860 million as the Company actively developed and
increased its acreage positions in several plays including the
Horn River basin.
E&D expenditures outside of North America increased
25 percent over 2009 to nearly $2.3 billion. E&D
spending in the North Sea was up $242 million over 2009
levels on construction of the Bacchus subsea tie-back project
and on the Forties Alpha satellite platform and ongoing upgrades
to existing platforms. Argentina expenditures were up on
additional drilling and development activity. Egypt was
$81 million higher than the prior year on continued
drilling activity in the Matruh and Faghur basins, where we have
announced numerous recent discoveries. E&D expenditures in
Australia and Chile were up marginally, increasing over
prior-year levels by $22 million and $9 million,
respectively.
60
Acquisitions We completed over
$11 billion of acquisitions in 2010 compared to
$310 million in 2009. We also assumed $847 million in
asset retirement costs. Acquisition capital expenditures occur
as attractive opportunities arise and, therefore, vary from year
to year. For information regarding our acquisitions, please see
Significant Acquisitions and Divestitures above and
Note 2 Acquisitions in the Notes to
Consolidated Financial Statements set forth in Part IV,
Item 15 of this
Form 10-K.
Asset Retirement Costs In 2010 we recorded
$459 million of additional future asset retirement costs
associated with our worldwide drilling programs and upward
revisions to prior-year estimates for timing and costs.
Gathering, Transmission and Processing Facilities
(GTP) We invested $506 million in GTP in
2010 compared to $305 million in 2009. GTP expenditures in
Australia consisted of construction activity at the Devil Creek
Gas Plant and the FEED study for the Wheatstone LNG project.
Activity in Canada was centered in the Horn River basin, with
expenditures for compressor stations, a water treatment
facility, gathering systems and a gas processing plant.
Expenditures in Egypt included the initial phases of the
Kalabsha oil processing facility. In addition, approximately
$517 million of the value of our 2010 acquisitions is
associated with GTP.
Dividends
The Company has paid cash dividends on its common stock for 46
consecutive years through 2010. Future dividend payments will
depend on the Companys level of earnings, financial
requirements and other relevant factors. Common stock dividends
paid during 2010 totaled $206 million, compared with
$201 million in 2009 and $234 million in 2008. The
2008 period included a special non-recurring cash dividend of 10
cents per common share paid on March 18, 2008. The Company
also made dividend payments of $20 million on the
Companys Series D Preferred Stock in 2010.
Liquidity
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
(In millions, except percentages)
|
|
2010
|
|
|
2009
|
|
|
Cash and cash equivalents
|
|
$
|
134
|
|
|
$
|
2,048
|
|
Total debt
|
|
|
8,141
|
|
|
|
5,067
|
|
Shareholders equity
|
|
|
24,377
|
|
|
|
15,779
|
|
Available committed borrowing capacity
|
|
|
2,387
|
|
|
|
2,300
|
|
Floating-rate debt/total debt
|
|
|
12
|
%
|
|
|
7
|
%
|
Percent of total debt to capitalization
|
|
|
25
|
%
|
|
|
24
|
%
|
Our liquidity and financial position have not been materially
affected by recent uncertainty in the credit markets. We believe
that losses from non-performance are unlikely to occur; however,
we are not able to predict sudden changes in the
creditworthiness of the financial institutions with which we do
business. Twenty-seven of 28 banks with lending commitments to
the Company have credit ratings of at least single-A, which in
some cases is based on government support. There is no assurance
that the financial condition of these banks will not deteriorate
or that the government guarantee will be maintained. We closely
monitor the ratings of the 28 banks in our bank group. Having a
large bank group allows the Company to mitigate the potential
impact of any banks failure to honor its lending
commitment.
Cash and
Cash Equivalents
We had $134 million in cash and cash equivalents at
December 31, 2010. At December 31, 2010,
$120 million of cash was held by foreign subsidiaries and
approximately $14 million was held by Apache Corporation
and U.S. subsidiaries. The cash held by foreign
subsidiaries is subject to additional U.S. income taxes if
repatriated. Almost all of the cash is denominated in
U.S. dollars and, at times, is invested in highly liquid,
investment-grade securities, with maturities of three months or
less at the time of purchase. We intend to use cash from our
international subsidiaries to fund international projects.
61
Debt
At December 31, 2010, outstanding debt, which consisted of
notes, debentures, commercial paper and uncommitted bank lines,
totaled $8.1 billion. Current debt consists of
$46 million borrowed under uncommitted money
market/overdraft lines of credit in the U.S. and Argentina.
We have $46 million of debt maturing in 2011,
$400 million maturing in 2012, $1.8 billion maturing
in 2013, $350 million maturing in 2015, and the remaining
$5.6 billion maturing intermittently in years 2016 through
2096.
Debt-to-Capitalization
Ratio
The Companys
debt-to-capitalization
ratio as of December 31, 2010 was 25 percent.
Available
Credit Facilities
As of December 31, 2010, the Company had unsecured
committed revolving syndicated bank credit facilities totaling
$3.3 billion, of which $1.0 billion matures in August
2011 and $2.3 billion matures in May 2013. The facilities
consist of a $1.0 billion
364-day
facility, a $1.5 billion facility and a $450 million
facility in the U.S., a $200 million facility in Australia
and a $150 million facility in Canada. The
$1.5 billion and the $450 million credit facilities
also allow the company to borrow under competitive auctions. The
U.S. credit facilities are used to support Apaches
commercial paper program.
The financial covenants of the credit facilities require the
Company to maintain a
debt-to-capitalization
ratio of not greater than 60 percent at the end of any
fiscal quarter. The negative covenants include restrictions on
the Companys ability to create liens and security
interests on our assets, with exceptions for liens typically
arising in the oil and gas industry, purchase money liens and
liens arising as a matter of law, such as tax and
mechanics liens. The Company may incur liens on assets
located in the U.S. and Canada of up to five percent of the
Companys consolidated assets, or approximately
$2.2 billion as of December 31, 2010. There are no
restrictions on incurring liens in countries other than
U.S. and Canada. There are also restrictions on
Apaches ability to merge with another entity, unless the
Company is the surviving entity, and a restriction on our
ability to guarantee debt of entities not within our
consolidated group.
There are no clauses in the facilities that permit the lenders
to accelerate payments or refuse to lend based on unspecified
material adverse changes. The credit facility agreements do not
have drawdown restrictions or prepayment obligations in the
event of a decline in credit ratings. However, the agreements
allow the lenders to accelerate payments and terminate lending
commitments if Apache Corporation, or any of its U.S. or
Canadian subsidiaries, defaults on any direct payment obligation
in excess of $100 million or has any unpaid, non-appealable
judgment against it in excess of $100 million. The Company
was in compliance with the terms of the credit facilities as of
December 31, 2010.
At the Companys option, the interest rate for the
facilities, excluding the
364-day
facility, is based on a base rate, as defined, or LIBOR plus a
margin determined by the Companys senior long-term debt
rating. In the case of the
364-day
facility, the margin over LIBOR varies based upon prices
reported in the credit default swap market with respect to
Apaches one-year indebtedness and the rating for
Apaches senior, unsecured long-term debt.
In 2010, one of the Companys Australian subsidiaries
repaid $350 million under its amortizing secured revolving
syndicated credit facility for its Van Gogh and Pyrenees oil
developments offshore Western Australia. Upon repayment of the
facility, all commitments under the facility were terminated and
assets secured by the facility were released.
At December 31, 2010, the margin over LIBOR for committed
loans was .19 percent on the $1.5 billion facility and
.23 percent on the $450 million facility in the U.S.,
the $200 million facility in Australia and the
$150 million facility in Canada. If the total amount of the
loans borrowed under the $1.5 billion facility equals or
exceeds 50 percent of the total facility commitments, then
an additional .05 percent will be added to the margins over
LIBOR. If the total amount of the loans borrowed under all of
the other three facilities equals or exceeds 50 percent of
the total facility commitments, then an additional
.10 percent will be added to the margins over LIBOR. The
Company also pays quarterly facility fees of .06 percent on
the total amount of the $1.5 billion facility and
62
.07 percent on the total amount of the other three
facilities. The facility fees vary based upon the Companys
senior long-term debt rating.
Commercial
Paper Program
In August 2010 the Company increased its commercial paper
program by $1 billion from $1.95 billion to
$2.95 billion. The commercial paper program generally
enables Apache to borrow funds for up to 270 days at
competitive interest rates. Our 2010 weighted-average interest
rate for commercial paper was .37 percent. If the Company
is unable to issue commercial paper following a significant
credit downgrade or dislocation in the market, the
Companys U.S. credit facilities are available as a
100-percent backstop. The commercial paper program is fully
supported by available borrowing capacity under
U.S. committed credit facilities, which expire in 2011 and
2013. As of December 31, 2010, the Company had
$913 million in commercial paper outstanding.
Contractual
Obligations
We are subject to various financial obligations and commitments
in the normal course of operations. These contractual
obligations represent known future cash payments that we are
required to make and relate primarily to long-term debt,
operating leases, pipeline transportation commitments and
international commitments. The Company expects to fund these
contractual obligations with cash generated from operating
activities.
The following table summarizes the Companys contractual
obligations as of December 31, 2010. For additional
information regarding these obligations, please see
Note 5 Debt and Note 8
Commitments and Contingencies in the Notes to Consolidated
Financial Statements set forth in Part IV, Item 15 of
this
Form 10-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 &
|
|
Contractual Obligations
|
|
Reference
|
|
Total
|
|
|
2011
|
|
|
2012-2014
|
|
|
2015-2016
|
|
|
Beyond
|
|
|
|
(In millions)
|
|
|
Debt, at face value
|
|
Note 5
|
|
$
|
8,190
|
|
|
$
|
46
|
|
|
$
|
2,213
|
|
|
$
|
766
|
|
|
$
|
5,165
|
|
Interest payments
|
|
Note 5
|
|
|
7,774
|
|
|
|
417
|
|
|
|
1,107
|
|
|
|
659
|
|
|
|
5,591
|
|
Drilling rig commitments
|
|
Note 8
|
|
|
392
|
|
|
|
303
|
|
|
|
89
|
|
|
|
|
|
|
|
|
|
Purchase obligations
|
|
Note 8
|
|
|
833
|
|
|
|
574
|
|
|
|
259
|
|
|
|
|
|
|
|
|
|
E&D commitments
|
|
Note 8
|
|
|
575
|
|
|
|
235
|
|
|
|
308
|
|
|
|
32
|
|
|
|
|
|
Firm transportation agreements
|
|
Note 8
|
|
|
809
|
|
|
|
137
|
|
|
|
423
|
|
|
|
170
|
|
|
|
79
|
|
Office and related equipment
|
|
Note 8
|
|
|
166
|
|
|
|
34
|
|
|
|
70
|
|
|
|
25
|
|
|
|
37
|
|
Oil and gas operations equipment
|
|
Note 8
|
|
|
476
|
|
|
|
85
|
|
|
|
146
|
|
|
|
55
|
|
|
|
190
|
|
Other
|
|
Note 8
|
|
|
5
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Obligations(a)(b)(c)(d)
|
|
|
|
$
|
19,220
|
|
|
$
|
1,836
|
|
|
$
|
4,615
|
|
|
$
|
1,707
|
|
|
$
|
11,062
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
This table does not include the estimated discounted liability
for dismantlement, abandonment and restoration costs of oil and
gas properties of $2.9 billion. For additional information
regarding asset retirement obligation, please see Note
4 Asset Retirement Obligation in the Notes to
Consolidated Financial Statements set forth in Part IV,
Item 15 of this
Form 10-K. |
|
(b) |
|
This table does not include the Companys $12 million
net liability for outstanding derivative instruments valued as
of December 31, 2010. For additional information regarding
derivative instruments, please see Note 3
Derivative Instruments and Hedging Activities in the Notes to
Consolidated Financial Statements set forth in Part IV,
Item 15 of this
Form 10-K. |
|
(c) |
|
This table does not include the Companys pension or
postretirement benefit obligations. For additional information
regarding pension and postretirement benefit obligations, please
see Note 8 Commitments and Contingencies in the
Notes to Consolidated Financial Statements set forth in
Part IV, Item 15 of this
Form 10-K. |
|
(d) |
|
This table does not include the Companys tax reserves. For
additional information regarding tax reserves, please see
Note 6 Income Taxes in the Notes to
Consolidated Financial Statements set forth in Part IV,
Item 15 of this
Form 10-K. |
63
Apache is also subject to various contingent obligations that
become payable only if certain events or rulings were to occur.
The inherent uncertainty surrounding the timing of and monetary
impact associated with these events or rulings prevents any
meaningful accurate measurement, which is necessary to assess
settlements resulting from litigation. Apaches management
feels that it has adequately reserved for its contingent
obligations, including approximately $135 million for
environmental remediation and approximately $14 million for
various contingent legal liabilities. For a detailed discussion
of the Companys environmental and legal contingencies,
please see Note 8 Commitments and Contingencies
in the Notes to Consolidated Financial Statements set forth in
Part IV, Item 15 of this
Form 10-K.
The Company also had approximately $106 million accrued as
of December 31, 2010, for an insurance contingency as a
member of Oil Insurance Limited (OIL). This insurance co-op
insures specific property, pollution liability and other
catastrophic risks of the Company. As part of its membership,
the Company is contractually committed to pay a withdrawal
premium if we elect to withdraw from OIL. Apache does not
anticipate withdrawal from the insurance pool; however, the
potential withdrawal premium is calculated annually based on
past losses and the nature of our asset base. The liability
reflecting this potential charge has been fully accrued.
Off-Balance
Sheet Arrangements
Apache does not currently utilize any off-balance sheet
arrangements with unconsolidated entities to enhance liquidity
and capital resource positions.
Insurance
Program
We maintain insurance coverage that includes coverage for
physical damage to our oil and gas properties, third party
liability, workers compensation and employers
liability, general liability, sudden pollution and other
coverage. Our insurance coverage includes deductibles that must
be met prior to recovery. Additionally, our insurance is subject
to exclusions and limitations and there is no assurance that
such coverage will adequately protect us against liability from
all potential consequences and damages.
In general, our current insurance policies covering physical
damage to our oil and gas assets provide $250 million per
occurrence with an additional $250 million per year.
Coverage for damage to our U.S. Gulf of Mexico assets
specifically resulting from a named windstorm, however, is
subject to a maximum of $250 million per named windstorm,
includes a self-insured retention of 40 percent of the
losses above a $100 million deductible, and is limited to
no more than two storms per year. In addition, our policies
covering physical damage to our North Sea oil and gas assets
provide $250 million per occurrence with an additional
$750 million per year.
Our various insurance policies also provide coverage for, among
other things, liability related to negative environmental
impacts of a sudden pollution event in the amount of
$750 million per occurrence, charterers legal
liability, in the amount of $1 billion per occurrence,
aircraft liability in the amount of $750 million per
occurrence, and general liability, employers liability and
auto liability in the amount of $500 million per
occurrence. Our service agreements, including drilling
contracts, generally indemnify Apache for injuries and death of
the service providers employees as well as contractors and
subcontractors hired by the service provider.
Our insurance policies generally renew in January and June of
each year. In light of the recent catastrophic accident in the
Gulf of Mexico, we may not be able to secure similar coverage
for the same costs. Future insurance coverage for our industry
could increase in cost and may include higher deductibles or
retentions. In addition, some forms of insurance may become
unavailable in the future or unavailable on terms that we
believe are economically acceptable.
Apache purchases multi-year political risk insurance from the
Overseas Private Investment Corporation (OPIC) and highly rated
international insurers covering its investments in Egypt. In the
aggregate, these policies, subject to the policy terms and
conditions, provide approximately $1 billion of coverage to
Apache covering losses arising from confiscation,
nationalization, and expropriation risks and currency
inconvertibility. In addition, the Company has a separate policy
with OPIC, which provides $300 million of coverage for
losses arising from (1) non-payment by EGPC of arbitral
awards covering amounts owed Apache on past due invoices and
(2) expropriation of
64
exportable petroleum when actions taken by the Government of
Egypt prevent Apache from exporting our share of production.
Critical
Accounting Policies and Estimates
Apache prepares its financial statements and the accompanying
notes in conformity with accounting principles generally
accepted in the United States of America, which require
management to make estimates and assumptions about future events
that affect the reported amounts in the financial statements and
the accompanying notes. Apache identifies certain accounting
policies as critical based on, among other things, their impact
on the portrayal of Apaches financial condition, results
of operations or liquidity and the degree of difficulty,
subjectivity and complexity in their deployment. Critical
accounting policies cover accounting matters that are inherently
uncertain because the future resolution of such matters is
unknown. Management routinely discusses the development,
selection and disclosure of each of the critical accounting
policies. Following is a discussion of Apaches most
critical accounting policies:
Reserves
Estimates
Effective December 31, 2009, Apache adopted revised oil and
gas disclosure requirements set forth by the
U.S. Securities and Exchange Commission (SEC) in Release
No. 33-8995,
Modernization of Oil and Gas Reporting and as
codified by the Financial Accounting Standards Board (FASB) in
Accounting Standards Codification (ASC) Topic 932,
Extractive Industries Oil and Gas. The
new rules include changes to the pricing used to estimate
reserves, the option to disclose probable and possible reserves,
revised definitions for proved reserves, additional disclosures
with respect to undeveloped reserves, and other new or revised
definitions and disclosures.
Proved oil and gas reserves are the estimated quantities of
natural gas, crude oil, condensate and NGLs that
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known
reservoirs under existing conditions, operating conditions, and
government regulations.
Proved undeveloped reserves include those reserves that are
expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is
required for recompletion. Undeveloped reserves may be
classified as proved reserves on undrilled acreage directly
offsetting development areas that are reasonably certain of
production when drilled, or where reliable technology provides
reasonable certainty of economic producibility. Undrilled
locations may be classified as having undeveloped reserves only
if a development plan has been adopted indicating that they are
scheduled to be drilled within five years, unless specific
circumstances justify a longer time.
Despite the inherent imprecision in these engineering estimates,
our reserves are used throughout our financial statements. For
example, since we use the
units-of-production
method to amortize our oil and gas properties, the quantity of
reserves could significantly impact our DD&A expense. Our
oil and gas properties are also subject to a ceiling
limitation based in part on the quantity of our proved reserves.
Finally, these reserves are the basis for our supplemental oil
and gas disclosures.
Reserves as of December 31, 2010 and 2009 were calculated
using an unweighted arithmetic average of commodity prices in
effect on the first day of each month, held flat for the life of
the production, except where prices are defined by contractual
arrangements. Reserves as of December 31, 2008 were
estimated using prices in effect at the end of that year, in
accordance with SEC guidance in effect prior to the issuance of
the Modernization Rules.
Apache has elected not to disclose probable and possible
reserves or reserve estimates in this filing.
Asset
Retirement Obligation (ARO)
The Company has significant obligations to remove tangible
equipment and restore land or seabed at the end of oil and gas
production operations. Apaches removal and restoration
obligations are primarily associated with plugging and
abandoning wells and removing and disposing of offshore oil and
gas platforms. Estimating the future restoration and removal
costs is difficult and requires management to make estimates and
judgments. Asset removal
65
technologies and costs are constantly changing, as are
regulatory, political, environmental, safety and public
relations considerations.
ARO associated with retiring tangible long-lived assets is
recognized as a liability in the period in which the legal
obligation is incurred and becomes determinable. The liability
is offset by a corresponding increase in the underlying asset.
The ARO liability reflects the estimated present value of the
amount of dismantlement, removal, site reclamation and similar
activities associated with Apaches oil and gas properties.
The Company utilizes current retirement costs to estimate the
expected cash outflows for retirement obligations. Inherent in
the present value calculation are numerous assumptions and
judgments including the ultimate settlement amounts, inflation
factors, credit adjusted discount rates, timing of settlement
and changes in the legal, regulatory, environmental and
political environments. To the extent future revisions to these
assumptions impact the present value of the existing ARO
liability, a corresponding adjustment is made to the oil and gas
property balance. Accretion expense is recognized over time as
the discounted liability is accreted to its expected settlement
value.
Income
Taxes
Our oil and gas exploration and production operations are
subject to taxation on income in numerous jurisdictions
worldwide. We record deferred tax assets and liabilities to
account for the expected future tax consequences of events that
have been recognized in our financial statements and our tax
returns. We routinely assess the realizability of our deferred
tax assets. If we conclude that it is more likely than not that
some portion or all of the deferred tax assets will not be
realized under accounting standards, the tax asset would be
reduced by a valuation allowance. Numerous judgments and
assumptions are inherent in the determination of future taxable
income, including factors such as future operating conditions
(particularly as related to prevailing oil and gas prices).
The Company regularly assesses and, if required, establishes
accruals for tax contingencies that could result from
assessments of additional tax by taxing jurisdictions in
countries where the Company operates. Tax reserves have been
established and include any related interest, despite the belief
by the Company that certain tax positions meet certain
legislative, judicial and regulatory requirements. These
reserves are subject to a significant amount of judgment and are
reviewed and adjusted on a periodic basis in light of changing
facts and circumstances considering the progress of ongoing tax
audits, case law and any new legislation. The Company believes
that the reserves established are adequate in relation to the
potential for any additional tax assessments.
Purchase
Price Allocation
Accounting for the acquisition of a business requires the
allocation of the purchase price to the various assets and
liabilities of the acquired business and recording deferred
taxes for any differences between the allocated values and tax
basis of assets and liabilities. Any excess of the purchase
price over the amounts assigned to assets and liabilities is
recorded as goodwill.
The purchase price allocation is accomplished by recording each
asset and liability at its estimated fair value. Estimated
deferred taxes are based on available information concerning the
tax basis of the acquired companys assets and liabilities
and tax-related carryforwards at the merger date, although such
estimates may change in the future as additional information
becomes known. The amount of goodwill recorded in any particular
business combination can vary significantly depending upon the
values attributed to assets acquired and liabilities assumed
relative to the total acquisition cost.
In estimating the fair values of assets acquired and liabilities
assumed we made various assumptions. The most significant
assumptions related to the estimated fair values assigned to
proved and unproved crude oil and natural gas properties. To
estimate the fair values of these properties, we prepared
estimates of crude oil and natural gas reserves as described
above in Reserve Estimates. Estimated fair values
assigned to assets acquired can have a significant effect on
results of operations in the future.
66
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ITEM 7A.
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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 exposure to market risk. The term market risk relates to the
risk of loss arising from adverse changes in oil, gas and NGL
prices, interest rates, foreign currency and adverse
governmental actions. The disclosures are not meant to be
precise indicators of expected future losses, but rather
indicators of reasonably possible losses. The forward-looking
information provides indicators of how we view and manage our
ongoing market risk exposures.
Commodity
Risk
The Companys revenues, earnings, cash flow, capital
investments and, ultimately, future rate of growth are highly
dependent on the prices we receive for our crude oil, natural
gas and NGLs, which have historically been very volatile due to
unpredictable events such as economic growth or retraction,
weather and climate. Our average monthly crude oil realizations
saw a gradual increase from a low of $70.68 per barrel in May
2010, peaking in December at $86.10. In 2010 crude oil prices
averaged $76.69 per barrel up 28 percent from 2009. Our
average monthly natural gas price realizations fluctuated
throughout 2010, dipping from a high of $4.84 per Mcf in
February to a low of $3.89 in September before increasing to
$4.19 in December. Average realized prices in 2010 for natural
gas increased 12 percent to $4.15 per Mcf.
For 2010 approximately 23 percent of our natural gas
production was subject to financial derivative hedges. As of
year-end 2010 we had just over 375,000 MMBtu per day of our
projected 2011 North American natural gas production hedged. For
perspective, these hedges cover 24 percent of
fourth-quarter 2010 North American daily production, or
16 percent of worldwide production.
Approximately 12 percent of our 2010 crude oil production
was subject to financial derivative hedges. We entered 2011
having hedged approximately 98,000 b/d of oil production. In
addition, Apache North Sea, Ltd. entered into a 2011 physical
sales contract to deliver 20 thousand barrels of oil per day
under a collar pricing arrangement. For perspective, the
combined 2011financial derivatives represent approximately
35 percent of our fourth-quarter 2010 worldwide daily oil
volumes.
Apache may use futures contracts, swaps, options and fixed-price
physical contracts to hedge its commodity prices. Realized gains
or losses from the Companys price-risk management
activities are recognized in oil and gas production revenues
when the associated production occurs. Apache does not hold or
issue derivative instruments for trading purposes.
On December 31, 2010, the Company had open natural gas
derivative hedges in an asset position with a fair value of
$454 million. A 10 percent increase in natural gas
prices would reduce the fair value by approximately
$104 million, while a 10 percent decrease in prices
would increase the fair value by approximately
$104 million. The Company also had open crude oil
derivatives in a liability position with a fair value of
$466 million. A 10 percent increase in oil prices
would increase the liability by approximately $356 million,
while a 10 percent decrease in prices would decrease the
liability by approximately $298 million. These fair value
changes assume volatility based on prevailing market parameters
at December 31, 2010. For notional volumes and terms
associated with the Companys derivative contracts, please
see Note 3 Derivative Instruments and Hedging
Activities in the Notes to Consolidated Financial Statements set
forth in Part IV, Item 15 of this
Form 10-K.
Apache conducts its risk management activities for its
commodities under the controls and governance of its risk
management policy. The Risk Management Committee approves and
oversees these controls, which have been implemented by
designated members of the treasury department. The treasury and
accounting departments also provide separate checks and reviews
on the results of hedging activities. Controls for our commodity
risk management activities include limits on credit, limits on
volume, segregation of duties, delegation of authority and a
number of other policy and procedural controls.
Interest
Rate Risk
On December 31, 2010, the Companys debt with fixed
interest rates represented approximately 88 percent of
total debt. As a result, the interest expense on approximately
12 percent of Apaches debt will fluctuate based on
67
short-term interest rates. A 10 percent change in floating
interest rates on year-end floating debt balances would change
annual interest expense by approximately $782,000.
Foreign
Currency Risk
The Companys cash flow stream relating to certain
international operations is based on the U.S. dollar
equivalent of cash flows measured in foreign currencies. In
Australia, oil production is sold under U.S. dollar
contracts, and gas production is sold largely under fixed-price
Australian dollar contracts. Approximately half the costs
incurred for Australian operations are paid in
U.S. dollars. In Canada, the majority of oil and gas
production is sold under Canadian dollar contracts. The majority
of the costs incurred are paid in Canadian dollars. The North
Sea production is sold under U.S. dollar contracts, and the
majority of costs incurred are paid in British pounds. In Egypt,
all oil and gas production is sold under U.S. dollar
contracts, and the majority of the costs incurred are
denominated in U.S. dollars. Argentine revenues and
expenditures are largely denominated in U.S. dollars but
converted into Argentine pesos at the time of payment. Revenue
and disbursement transactions denominated in Australian dollars,
Canadian dollars, British pounds, Egyptian pounds and Argentine
pesos are converted to U.S. dollar equivalents based on
average exchange rates during the period.
Foreign currency gains and losses also arise when monetary
assets and monetary liabilities denominated in foreign
currencies are translated at the end of each month. Currency
gains and losses are included as either a component of
Other under Revenues and Other or, as is
the case when we re-measure our foreign tax liabilities, as a
component of the Companys provision for income tax expense
on the Statement of Consolidated Operations. A 10 percent
strengthening or weakening of the Australian dollar, Canadian
dollar, British pound, Egyptian pound or Argentine peso as of
December 31, 2010, would result in a foreign currency net
loss or gain, respectively, of approximately $16 million.
Forward-Looking
Statements and Risk
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 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 that was used to prepare our estimate of proved
reserves as of December 31, 2010, 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, could, expect,
intend, project, estimate,
anticipate, plan, 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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the market prices of oil, natural gas, NGLs and other products
or services;
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our commodity hedging arrangements;
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the integration of Mariner and the BP properties;
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increased scrutiny from regulatory agencies due to the BP
acquisition;
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the supply and demand for oil, natural gas, NGLs and other
products or services;
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production and reserve levels;
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drilling risks;
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economic and competitive conditions;
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the availability of capital resources;
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68
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capital expenditure and other contractual obligations;
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the significant transaction and acquisition costs related to the
Mariner and BP property acquisitions;
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currency exchange rates;
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weather conditions;
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inflation rates;
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the availability of goods and services;
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legislative or regulatory changes;
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the impact on our operations due to the change in government in
Egypt;
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terrorism;
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occurrence of property acquisitions or divestitures;
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the securities or capital markets and related risks such as
general credit, liquidity, market and interest-rate
risks; and
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other factors disclosed under Items 1 and 2
Business and Properties Estimated Proved Reserves
and Future Net Cash Flows, Item 1A Risk
Factors, 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
Form 10-K.
|
All subsequent written and oral forward-looking statements
attributable to the Company, 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.
69
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ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
|
The financial statements and supplementary financial information
required to be filed under this item are presented on pages F-1
through F-67 in Part IV, Item 15 of this
Form 10-K
and are incorporated herein by reference.
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ITEM 9.
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
|
The financial statements for the fiscal years ended
December 31, 2010, 2009 and 2008, included in this report,
have been audited by Ernst & Young LLP, registered
public accounting firm, as stated in their audit report
appearing herein.
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ITEM 9A.
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CONTROLS
AND PROCEDURES
|
Disclosure
Controls and Procedures
G. Steven Farris, the Companys Chairman and Chief
Executive Officer, in his capacity as principal executive
officer, and Thomas P. Chambers, the Companys Executive
Vice President and Chief Financial Officer, in his capacity as
principal financial officer, evaluated the effectiveness of our
disclosure controls and procedures as of December 31, 2010,
the end of the period covered by this report. Based on that
evaluation and as of the date of that evaluation, these officers
concluded that the Companys disclosure controls and
procedures were effective, providing effective means to ensure
that the information we are required to disclose under
applicable laws and regulations is recorded, processed,
summarized and reported within the time periods specified in the
Commissions rules and forms and accumulated and
communicated to our management, including our principal
executive officer and principal financial officer, to allow
timely decisions regarding required disclosure. We also made no
changes in internal controls over financial reporting during the
quarter ending December 31, 2010, that have materially
affected, or are reasonably likely to materially affect, the
Companys internal control over financial reporting.
We periodically review the design and effectiveness of our
disclosure controls, including compliance with various laws and
regulations that apply to our operations both inside and outside
the United States. We make modifications to improve the design
and effectiveness of our disclosure controls and may take other
corrective action, if our reviews identify deficiencies or
weaknesses in our controls.
Managements
Report on Internal Control over Financial
Reporting
The management report called for by Item 308(a) of
Regulation S-K
is incorporated herein by reference to Report of
Management on Internal Control Over Financial Reporting,
included on
Page F-1
in Part IV, Item 15 of this
Form 10-K.
The independent auditors attestation report called for by
Item 308(b) of
Regulation S-K
is incorporated by reference to the Report of Independent
Registered Public Accounting Firm, included on
Page F-3
in Part IV, Item 15 of this
Form 10-K.
Changes
in Internal Control over Financial Reporting
There was no change in our internal controls over financial
reporting during the quarter ending December 31, 2010, that
has materially affected, or is reasonably likely to materially
affect, our internal controls over financial reporting.
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ITEM 9B.
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OTHER
INFORMATION
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None.
70
PART III
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ITEM 10.
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DIRECTORS
AND EXECUTIVE OFFICERS OF THE REGISTRANT
|
The information set forth under the captions Nominees for
Election as Directors, Continuing Directors,
Executive Officers of the Company, and
Securities Ownership and Principal Holders in the
proxy statement relating to the Companys 2011 annual
meeting of stockholders (the Proxy Statement) is incorporated
herein by reference.
Code
of Business Conduct
Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n)
of the NASDAQ, we are required to adopt a code of business
conduct and ethics for our directors, officers and employees. In
February 2004, the Board of Directors adopted the Code of
Business Conduct (Code of Conduct), and revised it in November
2010. The revised Code of Conduct also meets the requirements of
a code of ethics under Item 406 of
Regulation S-K.
You can access the Companys Code of Conduct on the
Governance page of the Companys website at
www.apachecorp.com. Any stockholder who so requests may obtain a
printed copy of the Code of Conduct by submitting a request to
the Companys corporate secretary at the address on the
cover of this
Form 10-K.
Changes in and waivers to the Code of Conduct for the
Companys directors, chief executive officer and certain
senior financial officers will be posted on the Companys
website within five business days and maintained for at least
12 months.
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ITEM 11.
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EXECUTIVE
COMPENSATION
|
The information set forth under the captions Compensation
Discussion and Analysis, Summary Compensation
Table, Grants of Plan Based Awards Table,
Outstanding Equity Awards at Fiscal Year-End Table,
Option Exercises and Stock Vested Table,
Non-Qualified Deferred Compensation Table,
Employment Contracts and Termination of Employment and
Change-in-Control
Arrangements and Director Compensation Table
in the Proxy Statement is incorporated herein by reference.
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ITEM 12.
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SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
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The information set forth under the captions Securities
Ownership and Principal Holders and Equity
Compensation Plan Information in the Proxy Statement is
incorporated herein by reference.
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ITEM 13.
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CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
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The information set forth under the captions Certain
Business Relationships and Transactions and Director
Independence in the Proxy Statement is incorporated herein
by reference.
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ITEM 14.
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PRINCIPAL
ACCOUNTANT FEES AND SERVICES
|
The information set forth under the caption Independent
Auditors in the Proxy Statement is incorporated herein by
reference.
71
PART IV
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ITEM 15.
|
EXHIBITS,
FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
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(a) Documents included in this report:
1. Financial Statements
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Report of management
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F-1
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Report of independent registered public accounting firm
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F-2
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Report of independent registered public accounting firm
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F-3
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Statement of consolidated operations for each of the three years
in the period ended December 31, 2009
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F-4
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Statement of consolidated cash flows for each of the three years
in the period ended December 31, 2009
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F-5
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Consolidated balance sheet as of December 31, 2009 and 2008
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F-6
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Statement of consolidated shareholders equity for each of
the three years in the period ended December 31, 2009
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F-7
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Notes to consolidated financial statements
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F-8
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2. Financial Statement Schedules
Financial statement schedules have been omitted because they are
either not required, not applicable or the information required
to be presented is included in the Companys financial
statements and related notes.
3. Exhibits
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Exhibit
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No.
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Description
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2
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.1
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Agreement and Plan of Merger, dated April 14, 2010, by and among
Registrant, ZMZ Acquisitions LLC, and Mariner Energy, Inc.
(incorporated by reference to Exhibit 2.1 to Registrants
Current Report on Form 8-K, dated April 14, 2010, filed April
16, 2010, SEC File No. 001-4300) (the schedules and annexes have
been omitted pursuant to Item 601(b)(2) of Regulation S-K).
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2
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.2
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Amendment No. 1, dated August 2, 2010, to Agreement and Plan of
Merger, dated April 14, 2010, by and among Registrant, ZMZ
Acquisitions LLC, and Mariner Energy, Inc. (incorporated by
reference to Exhibit 2.1 to Registrants Current Report on
Form 8-K, dated August 2, 2010, filed on August 3, 2010, SEC
File No. 001-4300) (the schedules and annexes have been omitted
pursuant to Item 601(b)(2) of Regulation S-K).
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2
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.3
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Purchase and Sale Agreement by and between BP America Production
Company and ZPZ Delaware I LLC dated July 20, 2010 (incorporated
by reference to Exhibit 2.1 to Registrants Current Report
on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC
File No. 001-4300) (the exhibits and schedules have been omitted
pursuant to Item 601(b)(2) of Regulation S-K).
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2
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.4
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Partnership Interest and Share Purchase and Sale Agreement by
and between BP Canada Energy and Apache Canada Ltd. dated July
20, 2010 (incorporated by reference to Exhibit 2.2 to
Registrants Current Report on Form 8-K/A, dated July 20,
2010, filed on July 21, 2010, SEC File No. 001-4300)(the
exhibits have been omitted pursuant to Item 601(b)(2) of
Regulation S-K).
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2
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.5
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Purchase and Sale Agreement by and among BP Egypt Company, BP
Exploration (Delta) Limited and ZPZ Egypt Corporation LDC dated
July 20, 2010 (incorporated by reference to Exhibit 2.3 to
Registrants Current Report on Form 8-K/A, dated July 20,
2010, filed on July 21, 2010, SEC File No. 001-4300) (the
exhibits and schedules have been omitted pursuant to Item
601(b)(2) of Regulation S-K).
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3
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.1
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Restated Certificate of Incorporation of Registrant, dated
February 23, 2010, as filed with the Secretary of State of
Delaware on February 23, 2010 (incorporated by reference to
Exhibit 3.1 to Registrants Annual Report on Form 10-K for
year ended December 31, 2009, SEC File No. 001-4300).
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72
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Exhibit
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No.
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Description
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3
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.2
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Certificate of Designations of the 6.00% Mandatory Convertible
Preferred Stock, Series D (incorporated by reference to Exhibit
3.3 to Registrants Registration Statement on Form 8-A,
dated July 29, 2010, SEC File No. 001-4300).
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3
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.3
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Bylaws of Registrant, as amended August 6, 2009 (incorporated by
reference to Exhibit 3.2 to Registrants Quarterly Report
on Form 10-Q for quarter ended June 30, 2009, SEC File No.
001-4300).
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4
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.1
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Form of Certificate for Registrants Common Stock
(incorporated by reference to Exhibit 4.1 to Registrants
Quarterly Report on Form 10-Q for the quarter ended March 31,
2004, SEC File No. 001-4300).
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4
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.2
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Form of Certificate for the 6.00% Mandatory Convertible
Preferred Stock, Series D (incorporated by reference to Exhibit
A of Exhibit 3.3 to Registrants Registration Statement on
Form 8-A, dated July 29, 2010, SEC File No. 001-4300).
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4
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.3
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Form of 3.625% Notes due 2021 (incorporated by reference to
Exhibit 4.1 to Registrants Current Report on Form 8-K,
dated November 30, 2010, filed on December 3, 2010, SEC File No.
001-4300).
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4
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.4
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Form of 5.250% Notes due 2042 (incorporated by reference to
Exhibit 4.2 to Registrants Current Report on Form 8-K,
dated November 30, 2010, filed on December 3, 2010, SEC File No.
001-4300).
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4
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.5
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Form of 5.100% Notes due 2040 (incorporated by reference to
Exhibit 4.1 to Registrants Current Report on Form 8-K,
dated August 17, 2010, filed on August 20, 2010, SEC File No.
001-4300).
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4
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.6
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Rights Agreement, dated January 31, 1996, between Registrant and
Wells Fargo Bank, N.A. (as successor-in-interest to Norwest Bank
Minnesota, N.A.), rights agent, relating to the declaration of a
rights dividend to Registrants common shareholders of
record on January 31, 1996 (incorporated by reference to Exhibit
(a) to Registrants Registration Statement on Form 8-A,
dated January 24, 1996, SEC File No. 001-4300).
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4
|
.7
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Amendment No. 1, dated as of January 31, 2006, to the Rights
Agreement dated as of December 31, 1996, between Apache
Corporation, a Delaware corporation, and Wells Fargo Bank, N.A.
(as successor-in-interest to Norwest Bank Minnesota, N.A.)
(incorporated by reference to Exhibit 4.4 to Registrants
Amendment No. 1 to Registration Statement on Form 8-A, dated
January 31, 2006, SEC File No. 001-4300).
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4
|
.8
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Senior Indenture, dated February 15, 1996, between Registrant
and The Bank of New York Mellon Trust Company, N.A. (formerly
known as the Bank of New York Trust Company, N.A., as
successor-in-interest to JPMorgan Chase Bank), formerly known as
The Chase Manhattan Bank, as trustee, governing the senior debt
securities and guarantees (incorporated by reference to Exhibit
4.6 to Registrants Registration Statement on Form S-3,
dated May 23, 2003, Reg. No. 333-105536).
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4
|
.9
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First Supplemental Indenture to the Senior Indenture, dated as
of November 5, 1996, between Registrant and The Bank of New York
Mellon Trust Company, N.A. (formerly known as the Bank of New
York Trust Company, N.A., as successor-in-interest to JPMorgan
Chase Bank, formerly known as The Chase Manhattan Bank), as
trustee, governing the senior debt securities and guarantees
(incorporated by reference to Exhibit 4.7 to Registrants
Registration Statement on Form S-3, dated May 23, 2003, Reg. No.
333-105536).
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4
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.10
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Form of Indenture among Apache Finance Pty Ltd, Registrant and
The Bank of New York Mellon Trust Company, N.A. (formerly known
as the Bank of New York Trust Company, N.A., as
successor-in-interest to The Chase Manhattan Bank), as trustee,
governing the debt securities and guarantees (incorporated by
reference to Exhibit 4.1 to Registrants Registration
Statement on Form S-3, dated November 12, 1997, Reg. No.
333-339973).
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4
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.11
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Form of Indenture among Registrant, Apache Finance Canada
Corporation and The Bank of New York Mellon Trust Company, N.A.
(formerly known as the Bank of New York Trust Company, N.A., as
successor-in-interest to The Chase Manhattan Bank), as trustee,
governing the debt securities and guarantees (incorporated by
reference to Exhibit 4.1 to Amendment No. 1 to Registrants
Registration Statement on Form S-3, dated November 12, 1999,
Reg. No. 333-90147).
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73
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Exhibit
|
|
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No.
|
|
|
|
Description
|
|
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4
|
.12
|
|
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Deposit Agreement, dated as of July 28, 2010, between
Registrants and Wells Fargo Bank, N.A., as depositary, on behalf
of all holders from time to time of the receipts issued there
under (incorporated by reference to Exhibit 4.2 to
Registrants Current Report on Form 8-K, dated July 22,
2010, filed on July 28, 2010, SEC File No. 001-4300).
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4
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.13
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Form of Depositary Receipt for the Depositary Shares
(incorporated by reference to Exhibit A to Exhibit 4.2 to
Registrants Current Report on Form 8-K, dated July 22,
2010, filed on July 28, 2010, SEC File No. 001-4300).
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4
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.14
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Form of Apache Corporation November 10, 2010 First Non-Qualified
Stock Option Agreements for Certain Employees of Apache
Corporation (incorporated by reference to Exhibit 4.6 to
Registrants Current Report on Form S-8 filed on November
10, 2010, SEC File No. 001-4300).
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4
|
.15
|
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|
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Form of Apache Corporation November 10, 2010 Second
Non-Qualified Stock Option Agreements for Certain Employees of
Apache Corporation (incorporated by reference to Exhibit 4.7 to
Registrants Current Report on Form S-8 filed on November
10, 2010, SEC File No. 001-4300).
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4
|
.16
|
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Form of Apache Corporation November 10, 2010 Non-StatutoryStock
Option Agreements for Certain Employees of Apache Corporation
(incorporated by reference to Exhibit 4.8 to Registrants
Current Report on Form S-8 filed on November 10, 2010, SEC File
No. 001-4300).
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10
|
.1
|
|
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Form of Amended and Restated Credit Agreement, dated as of May
9, 2006, among Registrant, the Lenders named therein, JPMorgan
Chase Bank, as Administrative Agent, Citibank, N.A. and Bank of
America, N.A., as Co-Syndication Agents, and BNP Paribas and UBS
Loan Finance LLC, as Co-Documentation Agents (incorporated by
reference to Exhibit 10.1 to Registrants Annual Report on
Form 10-K for year ended December 31, 2006, SEC File No.
001-4300).
|
|
10
|
.2
|
|
|
|
Form of Request for Approval of Extension of Maturity Date and
Amendment, dated as of April 5, 2007, among Registrant, the
Lenders named therein, JPMorgan Chase Bank, as Administrative
Agent, Citibank, N.A. and Bank of America, N.A., as
Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC,
as Co-Documentation Agents (incorporated by reference to Exhibit
10.2 to Registrants Annual Report on Form 10-K for year
ended December 31, 2007, SEC File No. 001-4300).
|
|
10
|
.3
|
|
|
|
Form of Request for Approval of Extension of Maturity Date and
Amendment, dated as of February 18, 2008, among Registrant, the
Lenders named therein, JPMorgan Chase Bank, as Administrative
Agent, Citibank, N.A. and Bank of America, N.A., as
Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC,
as Co-Documentation Agents (incorporated by reference to Exhibit
10.1 to Registrants Quarterly Report on Form 10-Q for the
quarter ended March 31, 2008, SEC File No. 001-4300).
|
|
10
|
.4
|
|
|
|
Form of Credit Agreement, dated as of May 12, 2005, among
Registrant, the Lenders named therein, JPMorgan Chase Bank,
N.A., as Global Administrative Agent, J.P. Morgan
Securities Inc. and Banc of America Securities, LLC, as Co-Lead
Arrangers and Joint Bookrunners, Bank of America, N.A. and
Citibank, N.A., as U.S. Co-Syndication Agents, and Calyon New
York Branch and SociétéGénérale, as U.S.
Co-Documentation Agents (excluding exhibits and schedules)
(incorporated by reference to Exhibit 10.1 to Registrants
Quarterly Report on Form 10-Q for the quarter ended June 30,
2005, SEC File No. 001-4300).
|
|
10
|
.5
|
|
|
|
Form of Credit Agreement, dated as of May 12, 2005, among Apache
Canada Ltd, a wholly-owned subsidiary of Registrant, the Lenders
named therein, JPMorgan Chase Bank, N.A., as Global
Administrative Agent, RBC Capital Markets and BMO Nesbitt Burns,
as Co-Lead Arrangers and Joint Bookrunners, Royal Bank of
Canada, as Canadian Administrative Agent, Bank of Montreal and
Union Bank of California, N.A., Canada Branch, as Canadian
Co-Syndication Agents, and The Toronto-Dominion Bank and BNP
Paribas (Canada), as Canadian Co-Documentation Agents (excluding
exhibits and schedules) (incorporated by reference to Exhibit
10.2 to Registrants Quarterly Report on Form 10-Q for the
quarter ended June 30, 2005, SEC File No. 001-4300).
|
74
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
No.
|
|
|
|
Description
|
|
|
10
|
.6
|
|
|
|
Form of Credit Agreement, dated as of May 12, 2005, among Apache
Energy Limited, a wholly-owned subsidiary of Registrant, the
Lenders named therein, JPMorgan Chase Bank, N.A., as Global
Administrative Agent, Citigroup Global Markets Inc. and Deutsche
Bank Securities Inc., as Co-Lead Arrangers and Joint
Bookrunners, Citisecurities Limited, as Australian
Administrative Agent, Deutsche Bank AG, Sydney Branch, and
JPMorgan Chase Bank, as Australian Co-Syndication Agents, and
Bank of America, N.A., Sydney Branch, and UBS AG, Australia
Branch, as Australian Co-Documentation Agents (excluding
exhibits and schedules) (incorporated by reference to Exhibit
10.3 to Registrants Quarterly Report on Form 10-Q for the
quarter ended June 30, 2005, SEC File No. 001-4300).
|
|
10
|
.7
|
|
|
|
Form of Request for Approval of Extension of Maturity Date and
Amendment, dated April 5, 2007, among Registrant, Apache Canada
Ltd., Apache Energy Limited, the Lenders named therein, JPMorgan
Chase Bank, N.A., as Global Administrative Agent, and the other
agents party thereto (incorporated by reference to Exhibit 10.6
to Registrants Annual Report on Form 10-K for year ended
December 31, 2007, SEC File No. 001-4300).
|
|
10
|
.8
|
|
|
|
Form of Request for Approval of Extension of Maturity Date and
Amendment, dated February 18, 2008, among Registrant, Apache
Canada Ltd., Apache Energy Limited, the Lenders named therein,
JPMorgan Chase Bank, N.A., as Global Administrative Agent, and
the other agents party thereto (incorporated by reference to
Exhibit 10.2 to Registrants Quarterly Report on Form 10-Q
for the quarter ended March 31, 2008, SEC File No. 001-4300).
|
|
10
|
.9
|
|
|
|
Credit Agreement, dated August 13, 2010, among Registrant, JP
Morgan Chase Bank, N.A., as Administrative Agent, and Citibank,
N.A., Bank Of America, N.A. and Goldman Sachs Bank USA, as
Co-Syndication Agents, J.P. Morgan Securities Inc.,
Citigroup Global Markets Inc., Banc Of America Securities, LLC
and Goldman Sachs Bank USA, As Co-Lead Arrangers and Joint
Bookrunners, and the lenders party thereto (excluding exhibits
and schedules) (incorporated by reference to Exhibit 10.1 to
Registrants Current Report on Form 8-K filed August 16,
2010).
|
|
10
|
.10
|
|
|
|
Apache Corporation Corporate Incentive Compensation Plan A
(Senior Officers Plan), dated July 16, 1998 (incorporated
by reference to Exhibit 10.13 to Registrants Annual Report
on Form 10-K for year ended December 31, 1998, SEC File No.
001-4300).
|
|
10
|
.11
|
|
|
|
First Amendment to Apache Corporation Corporate Incentive
Compensation Plan A, dated November 20, 2008, effective as of
January 1, 2005 (incorporated by reference to Exhibit 10.17 to
Registrants Annual Report on Form 10-K for year ended
December 31, 2008, SEC File No. 001-4300).
|
|
10
|
.12
|
|
|
|
Apache Corporation Corporate Incentive Compensation Plan B
(Strategic Objectives Format), dated July 16, 1998 (incorporated
by reference to Exhibit 10.14 to Registrants Annual Report
on Form 10-K for year ended December 31, 1998, SEC File No.
001-4300).
|
|
10
|
.13
|
|
|
|
First Amendment to Apache Corporation Corporate Incentive
Compensation Plan B, dated November 20, 2008, effective as of
January 1, 2005 (incorporated by reference to Exhibit 10.19 to
Registrants Annual Report on Form 10-K for year ended
December 31, 2008, SEC File No. 001-4300).
|
|
*10
|
.14
|
|
|
|
Apache Corporation 401(k) Savings Plan, as amended and restated,
dated October 28, 2010.
|
|
*10
|
.15
|
|
|
|
Amendment to Apache Corporation 401(k) Savings Plan, dated
December 30, 2010, effective as of November 10, 2010, except as
otherwise specified.
|
|
10
|
.16
|
|
|
|
Non-Qualified Retirement/Savings Plan of Apache Corporation, as
amended and restated July 14, 2010, except as otherwise
specified (incorporated by reference to Exhibit 10.3 to
Registrants Quarterly Report on Form 10-Q for the quarter
ended June 30, 2010, SEC File No. 001-4300).
|
|
10
|
.17
|
|
|
|
Apache Corporation 2007 Omnibus Equity Compensation Plan, as
amended and restated July 13, 2010, effective December 31, 2009
(incorporated by reference to Exhibit 10.4 to Registrants
Quarterly Report on Form 10-Q for the quarter ended June 30,
2010, SEC File No. 001-4300).
|
|
10
|
.18
|
|
|
|
Apache Corporation 1998 Stock Option Plan, as amended and
restated August 14, 2008 (incorporated by reference to Exhibit
10.3 to Registrants Quarterly Report on Form 10-Q for the
quarter ended September 30, 2008, SEC File No. 001-4300).
|
75
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
No.
|
|
|
|
Description
|
|
|
10
|
.19
|
|
|
|
Apache Corporation 2000 Stock Option Plan, as amended and
restated August 14, 2008 (incorporated by reference to Exhibit
10.4 to Registrants Quarterly Report on Form 10-Q for the
quarter ended September 30, 2008, SEC File No. 001-4300).
|
|
10
|
.20
|
|
|
|
Apache Corporation 2003 Stock Appreciation Rights Plan, as
amended and restated August 14, 2008 (incorporated by reference
to Exhibit 10.5 to Registrants Quarterly Report on Form
10-Q for quarter ended September 30, 2008, SEC File No.
001-4300).
|
|
10
|
.21
|
|
|
|
Apache Corporation 2005 Stock Option Plan, as amended and
restated August 14, 2008 (incorporated by reference to Exhibit
10.6 to Registrants Quarterly Report on Form 10-Q for
quarter ended September 30, 2008, Commission File No. 001-4300).
|
|
10
|
.22
|
|
|
|
Apache Corporation 2005 Share Appreciation Plan, as amended
and restated August 14, 2008 (incorporated by reference to
Exhibit 10.7 to Registrants Quarterly Report on Form 10-Q
for the quarter ended September 30, 2008, Commission File No.
001-4300).
|
|
10
|
.23
|
|
|
|
Apache Corporation 2008 Share Appreciation Program
Specifications, pursuant to Apache Corporation 2007 Omnibus
Equity Compensation Plan (incorporated by reference to Exhibit
10.3 to Registrants Quarterly Report on Form 10-Q for the
quarter ended March 31, 2008, SEC File No. 001-4300).
|
|
10
|
.24
|
|
|
|
Apache Corporation Executive Restricted Stock Plan, as amended
and restated November 19, 2008(incorporated by reference to
Exhibit 10.37 to Registrants Annual Report on Form 10-K
for year ended December 31, 2008, SEC File No. 001-4300).
|
|
10
|
.25
|
|
|
|
Apache Corporation Income Continuance Plan, as amended and
restated July 14, 2010, effective January 1, 2009 (incorporated
by reference to Exhibit 10.5 to Registrants Quarterly
Report on Form 10-Q for the quarter ended June 30, 2010, SEC
File No. 001-4300).
|
|
10
|
.26
|
|
|
|
Apache Corporation Deferred Delivery Plan, as amended and
restated July 13, 2010, effective January 1, 2009 (incorporated
by reference to Exhibit 10.6 to Registrants Quarterly
Report on Form 10-Q for the quarter ended June 30, 2010, SEC
File No. 001-4300).
|
|
10
|
.27
|
|
|
|
Apache Corporation Non-Employee Directors Compensation
Plan, as amended and restated November 20, 2008, effective as of
January 1, 2009 (incorporated by reference to Exhibit 10.38 to
Registrants Annual Report on Form 10-K for year ended
December 31, 2008, SEC File No. 001-4300).
|
|
10
|
.28
|
|
|
|
Apache Corporation Outside Directors Retirement Plan, as
amended and restated July 14, 2010, effective January 1, 2009
(incorporated by reference to Exhibit 10.7 to Registrants
Quarterly Report on Form 10-Q for the quarter ended June 30,
2010, SEC File No. 001-4300).
|
|
10
|
.29
|
|
|
|
Apache Corporation Equity Compensation Plan for Non-Employee
Directors, as amended and restated February 8, 2007
(incorporated by reference to Exhibit 10.2 to Registrants
Quarterly Report on Form 10-Q for quarter ended March 31, 2007,
SEC File No. 001-4300).
|
|
10
|
.30
|
|
|
|
Apache Corporation Non-Employee Directors Restricted Stock
Units Program Specifications, dated August 14, 2008, pursuant to
Apache Corporation 2007 Omnibus Equity Compensation Plan
(incorporated by reference to Exhibit 10.9 to Registrants
Quarterly Report on Form 10-Q for the quarter ended September
30, 2008, SEC File No. 001-4300).
|
|
10
|
.31
|
|
|
|
Restated Employment and Consulting Agreement, dated January 15,
2009, between Registrant and Raymond Plank (incorporated by
reference to Exhibit 10.1 to Registrants Current Report on
Form 8-K, dated January 15, 2009, filed January 16, 2009, SEC
File No. 001-4300).
|
|
10
|
.32
|
|
|
|
Amended and Restated Employment Agreement, dated December 20,
1990, between Registrant and John A. Kocur (incorporated by
reference to Exhibit 10.10 to Registrants Annual Report on
Form 10-K for year ended December 31, 1990, SEC File No.
001-4300).
|
|
10
|
.33
|
|
|
|
Employment Agreement between Registrant and G. Steven Farris,
dated June 6, 1988, and First Amendment, dated November 20,
2008, effective as of January 1, 2005 (incorporated by reference
to Exhibit 10.44 to Registrants Annual Report on Form 10-K
for year ended December 31, 2008, SEC File No. 001-4300).
|
76
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
No.
|
|
|
|
Description
|
|
|
10
|
.34
|
|
|
|
Amended and Restated Conditional Stock Grant Agreement, dated
September 15, 2005, effective January 1, 2005, between
Registrant and G. Steven Farris (incorporated by reference to
Exhibit 10.06 to Registrants Quarterly Report on Form 10-Q
for the quarter ended September 30, 2005, SEC File No. 001-4300).
|
|
10
|
.35
|
|
|
|
Restricted Stock Unit Award Agreement, dated May 8, 2008,
between Registrant and G. Steven Farris (incorporated by
reference to Exhibit 10.4 to Registrants Quarterly Report
on Form 10-Q for quarter ended March 31, 2008, SEC File No.
001-4300).
|
|
10
|
.36
|
|
|
|
Form of Restricted Stock Unit Award Agreement, dated February
12, 2009, between Registrant and each of John A. Crum, Rodney J.
Eichler, and Roger B. Plank (incorporated by reference to
Exhibit 10.1 to Registrants Current Report on Form 8-K,
dated February 12, 2009, filed February 18, 2009, SEC File No.
001-4300).
|
|
10
|
.37
|
|
|
|
Form of Restricted Stock Unit Award Agreement, dated November
18, 2009, between Registrant and Michael S. Bahorich
(incorporated by reference to Exhibit 10.37 to Registrants
Annual Report on Form 10-K for year ended December 31, 2009, SEC
File No. 001-4300).
|
|
10
|
.38
|
|
|
|
Form of Restricted Stock Unit Grant Agreement, dated May 6,
2009, between Registrant and each of G. Steven Farris, Roger B.
Plank, John A. Crum, Rodney J. Eichler, and Michael S. Bahorich
(incorporated by reference to Exhibit 10.38 to Registrants
Annual Report on Form 10-K for year ended December 31, 2009, SEC
File No. 001-4300).
|
|
10
|
.39
|
|
|
|
Form of Stock Option Award Agreement, dated May 6, 2009, between
Registrant and each of G. Steven Farris, Roger B. Plank, John A.
Crum, Rodney J. Eichler, and Michael S. Bahorich (incorporated
by reference to Exhibit 10.39 to Registrants Annual Report
on Form 10-K for year ended December 31, 2009, SEC File No.
001-4300).
|
|
10
|
.40
|
|
|
|
Form of 2010 Performance Program Agreement, dated January 15,
2010, between Registrant and each of G. Steven Farris, John A.
Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by
reference to Exhibit 10.1 to Registrants Current Report on
Form 8-K filed January 19, 2010, SEC File No. 001-4300).
|
|
10
|
.41
|
|
|
|
Form of First Amendment, effective May 5, 2010, to 2010
Performance Program Agreement, dated January 15, 2010, between
Registrant and each of G. Steven Farris, John A. Crum, Rodney J.
Eichler, and Roger B. Plank (incorporated by reference to
Exhibit 10.1 to Registrants Current Report on Form 8-K
filed May 11, 2010, SEC File No. 001-4300).
|
|
10
|
.42
|
|
|
|
Form of Restricted Stock Unit Award Agreement, dated January 15,
2010, between Registrant and each of John A. Crum, Rodney J.
Eichler, and Roger B. Plank (incorporated by reference to
Exhibit 10.2 to Registrants Current Report on Form 8-K
filed January 19, 2010, SEC File No. 001-4300).
|
|
10
|
.43
|
|
|
|
Form of 2011 Performance Program Agreement, dated January 7,
2011, between Registrant and each of G. Steven Farris, John A.
Crum, Rodney J. Eichler, Roger B. Plank, Michael S. Bahorich,
and Thomas P. Chambers (incorporated by reference to Exhibit
10.1 to Registrants Current Report on Form 8-K filed
January 13, 2011, SEC File No. 001-4300).
|
|
10
|
.44
|
|
|
|
Restricted Stock Unit Award Agreement, dated February 9, 2011,
between Registrant and Mr. Thomas P. Chambers (incorporated by
reference to Exhibit 10.1 to Registrants Current Report on
Form 8-K filed February 14, 2011, SEC File No. 001-4300).
|
|
*12
|
.1
|
|
|
|
Statement of Computation of Ratios of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock Dividends.
|
|
*14
|
.1
|
|
|
|
Code of Business Conduct
|
|
*21
|
.1
|
|
|
|
Subsidiaries of Registrant
|
|
*23
|
.1
|
|
|
|
Consent of Ernst & Young LLP
|
|
*23
|
.2
|
|
|
|
Consent of Ryder Scott Company L.P., Petroleum Consultants
|
|
*24
|
.1
|
|
|
|
Power of Attorney (included as a part of the signature pages to
this report)
|
|
*31
|
.1
|
|
|
|
Certification of Principal Executive Officer
|
|
*31
|
.2
|
|
|
|
Certification of Principal Financial Officer
|
|
*32
|
.1
|
|
|
|
Certification of Principal Executive Officer and Principal
Financial Officer
|
77
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
No.
|
|
|
|
Description
|
|
|
*99
|
.1
|
|
|
|
Report of Ryder Scott Company L.P., Petroleum Consultants
|
|
**101
|
|
|
|
|
The following materials from the Apache Corporations
Annual Report on Form 10-K for the year ended December 31, 2010,
formatted in XBRL (Extensible Business Reporting Language): (i)
Statement of Consolidated Operations, (ii) Statement of
Consolidated Cash Flows, (iii) Consolidated Balance Sheet, (iv)
Statement of Consolidated Shareholders Equity, and (v)
Notes to Consolidated Financial Statements, tagged as blocks of
text.
|
|
|
|
* |
|
Filed herewith. |
|
** |
|
Furnished herewith. |
|
|
|
Management contracts or compensatory plans or arrangements
required to be filed herewith pursuant to Item 15 hereof. |
NOTE: Debt instruments of the Registrant
defining the rights of long-term debt holders in principal
amounts not exceeding 10 percent of the Registrants
consolidated assets have been omitted and will be provided to
the Commission upon request.
78
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,
hereunto duly authorized.
APACHE CORPORATION
G. Steven Farris
Chairman of the Board and Chief Executive Officer
Dated: February 28, 2011
POWER OF
ATTORNEY
The officers and directors of Apache Corporation, whose
signatures appear below, hereby constitute and appoint G. Steven
Farris, Thomas P. Chambers, P. Anthony Lannie and Rebecca A.
Hoyt, and each of them (with full power to each of them to act
alone), the true and lawful attorney-in-fact to sign and
execute, on behalf of the undersigned, any amendment(s) to this
report and each of the undersigned does hereby ratify and
confirm all that said attorneys shall do or cause to be done by
virtue thereof.
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.
|
|
|
|
|
|
|
Name
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ G.
STEVEN FARRIS
G.
Steven Farris
|
|
Chairman of the Board and Chief
Executive Officer
(principal executive officer)
|
|
February 28, 2011
|
|
|
|
|
|
/s/ THOMAS
P. CHAMBERS
Thomas
P. Chambers
|
|
Executive Vice President and Chief Financial Officer
(principal financial officer)
|
|
February 28, 2011
|
|
|
|
|
|
/s/ REBECCA
A. HOYT
Rebecca
A. Hoyt
|
|
Vice President, Chief Accounting Officer and Controller
(principal accounting officer)
|
|
February 28, 2011
|
|
|
|
|
|
/s/ FREDERICK
M. BOHEN
Frederick
M. Bohen
|
|
Director
|
|
February 28, 201
|
|
|
|
|
|
/s/ RANDOLPH
M. FERLIC
Randolph
M. Ferlic
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ EUGENE
C. FIEDOREK
Eugene
C. Fiedorek
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ A.D.
FRAZIER, JR.
A.D.
Frazier, Jr.
|
|
Director
|
|
February 28, 2011
|
79
|
|
|
|
|
|
|
Name
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ PATRICIA
ALBJERG GRAHAM
Patricia
Albjerg Graham
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ SCOTT
D. JOSEY
Scott
D. Josey
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ CHANSOO
JOUNG
Chansoo
Joung
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ JOHN
A. KOCUR
John
A. Kocur
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ GEORGE
D. LAWRENCE
George
D. Lawrence
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ F.
H. MERELLI
F.
H. Merelli
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ RODMAN
D. PATTON
Rodman
D. Patton
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ CHARLES
J. PITMAN
Charles
J. Pitman
|
|
Director
|
|
February 28, 2011
|
80
REPORT OF
MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL
REPORTING
Management of the Company is responsible for the preparation and
integrity of the consolidated financial statements appearing in
this annual report on
Form 10-K.
The financial statements were prepared in conformity with
accounting principles generally accepted in the United States
and include amounts that are based on managements best
estimates and judgments.
Management of the Company is responsible for establishing and
maintaining effective internal control over financial reporting
as such term is defined in
Rule 13a-15(f)
under the Securities Exchange Act of 1934. The Companys
internal control over financial reporting is designed to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of the consolidated financial
statements. Our internal control over financial reporting is
supported by a program of internal audits and appropriate
reviews by management, written policies and guidelines, careful
selection and training of qualified personnel and a written code
of business conduct adopted by our Companys board of
directors, applicable to all Company directors and all officers
and employees of our Company and subsidiaries.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements and
even when determined to be effective, can only provide
reasonable assurance with respect to financial statement
preparation and presentation. 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.
Management assessed the effectiveness of the Companys
internal control over financial reporting as of
December 31, 2010. In making this assessment, management
used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in Internal
Control Integrated Framework. Based on our
assessment, management believes that the Company maintained
effective internal control over financial reporting as of
December 31, 2010.
The Companys independent auditors, Ernst & Young
LLP, a registered public accounting firm, are appointed by the
Audit Committee of the Companys board of directors.
Ernst & Young LLP have audited and reported on the
consolidated financial statements of Apache Corporation and
subsidiaries, and the effectiveness of the Companys
internal control over financial reporting. The reports of the
independent auditors follow this report on pages F-2 and F-3.
/s/ G.
Steven Farris
Chairman of the Board and Chief Executive Officer
(principal executive officer)
/s/ Thomas
P. Chambers
Executive Vice President and Chief Financial Officer
(principal financial officer)
/s/ Rebecca
A. Hoyt
Vice President, Chief Accounting Officer and Controller
(principal accounting officer)
Houston, Texas
February 28, 2011
F-1
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of Apache Corporation:
We have audited the accompanying consolidated balance sheets of
Apache Corporation and subsidiaries as of December 31, 2010
and 2009, and the related consolidated statements of operations,
shareholders equity, and cash flows for each of the three
years in the period ended December 31, 2010. These
financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements 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 audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Apache Corporation and subsidiaries at
December 31, 2010 and 2009, and the consolidated results of
their operations and their cash flows for each of the three
years in the period ended December 31, 2010, in conformity
with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial
statements, in 2009, the Company adopted SEC Release
33-8995 and
the amendments to ASC Topic 932, Extractive
Industries Oil and Gas, resulting from ASU
2010-03
(collectively, the Modernization Rules).
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States),
Apache Corporations internal control over financial
reporting as of December 31, 2010, based on criteria
established in Internal Control Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated
February 28, 2011, expressed an unqualified opinion thereon.
Houston, Texas
February 28, 2011
F-2
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of Apache Corporation:
We have audited Apache Corporation and subsidiaries
internal control over financial reporting as of
December 31, 2010, based on criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (the COSO criteria). Apache Corporation and
subsidiaries management is responsible for maintaining
effective internal control over financial reporting, and for its
assessment of the effectiveness of internal control over
financial reporting included in the accompanying Report of
Management on Internal Control over Financial Reporting. Our
responsibility is to express an opinion on the companys
internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
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, Apache Corporation and subsidiaries maintained,
in all material respects, effective internal control over
financial reporting as of December 31, 2010, based on the
COSO criteria.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Apache Corporation and
subsidiaries as of December 31, 2010 and 2009, and the
related consolidated statements of operations,
shareholders equity, and cash flows for each of the three
years in the period ended December 31, 2010 of Apache
Corporation and subsidiaries, and our report dated
February 28, 2011, expressed an unqualified opinion thereon.
Houston, Texas
February 28, 2011
F-3
APACHE
CORPORATION AND SUBSIDIARIES
STATEMENT
OF CONSOLIDATED OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions, except per common share data)
|
|
|
REVENUES AND OTHER:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues
|
|
$
|
12,183
|
|
|
$
|
8,574
|
|
|
$
|
12,328
|
|
Other
|
|
|
(91
|
)
|
|
|
41
|
|
|
|
62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,092
|
|
|
|
8,615
|
|
|
|
12,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring
|
|
|
3,083
|
|
|
|
2,395
|
|
|
|
2,516
|
|
Additional
|
|
|
|
|
|
|
2,818
|
|
|
|
5,334
|
|
Asset retirement obligation accretion
|
|
|
111
|
|
|
|
105
|
|
|
|
101
|
|
Lease operating expenses
|
|
|
2,032
|
|
|
|
1,662
|
|
|
|
1,910
|
|
Gathering and transportation
|
|
|
178
|
|
|
|
143
|
|
|
|
157
|
|
Taxes other than income
|
|
|
690
|
|
|
|
580
|
|
|
|
985
|
|
General and administrative
|
|
|
380
|
|
|
|
344
|
|
|
|
289
|
|
Merger, acquisitions & transition
|
|
|
183
|
|
|
|
|
|
|
|
|
|
Financing costs, net
|
|
|
229
|
|
|
|
242
|
|
|
|
166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,886
|
|
|
|
8,289
|
|
|
|
11,458
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES
|
|
|
5,206
|
|
|
|
326
|
|
|
|
932
|
|
Current income tax provision
|
|
|
1,222
|
|
|
|
842
|
|
|
|
1,456
|
|
Deferred income tax provision (benefit)
|
|
|
952
|
|
|
|
(231
|
)
|
|
|
(1,236
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
|
3,032
|
|
|
|
(285
|
)
|
|
|
712
|
|
Preferred stock dividends
|
|
|
32
|
|
|
|
7
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
|
|
$
|
3,000
|
|
|
$
|
(292
|
)
|
|
$
|
706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) PER COMMON SHARE:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
8.53
|
|
|
$
|
(0.87
|
)
|
|
$
|
2.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
8.46
|
|
|
$
|
(0.87
|
)
|
|
$
|
2.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes to consolidated financial statements are
an integral part of this statement.
F-4
APACHE
CORPORATION AND SUBSIDIARIES
STATEMENT
OF CONSOLIDATED CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
3,032
|
|
|
$
|
(285
|
)
|
|
$
|
712
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
3,083
|
|
|
|
5,213
|
|
|
|
7,850
|
|
Asset retirement obligation accretion
|
|
|
111
|
|
|
|
105
|
|
|
|
101
|
|
Provision for (benefit from) deferred income taxes
|
|
|
952
|
|
|
|
(231
|
)
|
|
|
(1,236
|
)
|
Other
|
|
|
190
|
|
|
|
183
|
|
|
|
(51
|
)
|
Changes in operating assets and liabilities, net of effects of
acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(496
|
)
|
|
|
(187
|
)
|
|
|
571
|
|
Inventories
|
|
|
35
|
|
|
|
(5
|
)
|
|
|
(22
|
)
|
Drilling advances
|
|
|
(28
|
)
|
|
|
(143
|
)
|
|
|
29
|
|
Deferred charges and other
|
|
|
(141
|
)
|
|
|
148
|
|
|
|
(324
|
)
|
Accounts payable
|
|
|
214
|
|
|
|
(180
|
)
|
|
|
(71
|
)
|
Accrued expenses
|
|
|
(309
|
)
|
|
|
(330
|
)
|
|
|
(457
|
)
|
Deferred credits and noncurrent liabilities
|
|
|
83
|
|
|
|
(64
|
)
|
|
|
(37
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY OPERATING ACTIVITIES
|
|
|
6,726
|
|
|
|
4,224
|
|
|
|
7,065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas property
|
|
|
(4,407
|
)
|
|
|
(3,326
|
)
|
|
|
(5,144
|
)
|
Additions to gathering, transmission and processing facilities
|
|
|
(515
|
)
|
|
|
(306
|
)
|
|
|
(679
|
)
|
Acquisition of Marathon properties
|
|
|
|
|
|
|
(181
|
)
|
|
|
|
|
Acquisition of Devon properties
|
|
|
(1,018
|
)
|
|
|
|
|
|
|
|
|
Acquisition of BP properties and facilities
|
|
|
(6,429
|
)
|
|
|
|
|
|
|
|
|
Mariner Energy, Inc. merger
|
|
|
(787
|
)
|
|
|
|
|
|
|
|
|
Acquisitions, other
|
|
|
(126
|
)
|
|
|
(129
|
)
|
|
|
(150
|
)
|
Short-term investments
|
|
|
|
|
|
|
792
|
|
|
|
(792
|
)
|
Restricted cash
|
|
|
|
|
|
|
14
|
|
|
|
(14
|
)
|
Proceeds from sale of oil and gas properties
|
|
|
|
|
|
|
3
|
|
|
|
308
|
|
Other, net
|
|
|
(121
|
)
|
|
|
(114
|
)
|
|
|
(64
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH USED IN INVESTING ACTIVITIES
|
|
|
(13,403
|
)
|
|
|
(3,247
|
)
|
|
|
(6,535
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commercial paper, credit facility and bank notes, net
|
|
|
(32
|
)
|
|
|
248
|
|
|
|
(100
|
)
|
Fixed-rate debt borrowings
|
|
|
2,470
|
|
|
|
|
|
|
|
796
|
|
Payments on fixed-rate notes
|
|
|
(1,023
|
)
|
|
|
(100
|
)
|
|
|
|
|
Proceeds from issuance of common stock
|
|
|
2,258
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of mandatory convertible preferred stock
|
|
|
1,227
|
|
|
|
|
|
|
|
|
|
Dividends paid
|
|
|
(226
|
)
|
|
|
(209
|
)
|
|
|
(239
|
)
|
Common stock activity
|
|
|
70
|
|
|
|
28
|
|
|
|
31
|
|
Redemption of preferred stock
|
|
|
|
|
|
|
(98
|
)
|
|
|
|
|
Other
|
|
|
19
|
|
|
|
21
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
|
|
4,763
|
|
|
|
(110
|
)
|
|
|
525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
|
|
(1,914
|
)
|
|
|
867
|
|
|
|
1,055
|
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
|
|
2,048
|
|
|
|
1,181
|
|
|
|
126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
|
$
|
134
|
|
|
$
|
2,048
|
|
|
$
|
1,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY CASH FLOW DATA:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid, net of capitalized interest
|
|
$
|
187
|
|
|
$
|
243
|
|
|
$
|
171
|
|
Income taxes paid, net of refunds
|
|
|
1,170
|
|
|
|
686
|
|
|
|
1,695
|
|
The accompanying notes to consolidated financial statements are
an integral part of this statement.
F-5
APACHE
CORPORATION AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEET
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In millions)
|
|
|
ASSETS
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
134
|
|
|
$
|
2,048
|
|
Receivables, net of allowance
|
|
|
2,134
|
|
|
|
1,546
|
|
Inventories
|
|
|
564
|
|
|
|
533
|
|
Drilling advances
|
|
|
259
|
|
|
|
231
|
|
Prepaid assets and other
|
|
|
389
|
|
|
|
228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,480
|
|
|
|
4,586
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
Oil and gas, on the basis of full-cost accounting:
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
57,904
|
|
|
|
44,267
|
|
Unproved properties and properties under development, not being
amortized
|
|
|
5,048
|
|
|
|
1,479
|
|
Gathering, transmission and processing facilities
|
|
|
4,212
|
|
|
|
3,189
|
|
Other
|
|
|
582
|
|
|
|
493
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67,746
|
|
|
|
49,428
|
|
Less: Accumulated depreciation, depletion and amortization
|
|
|
(29,595
|
)
|
|
|
(26,527
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
38,151
|
|
|
|
22,901
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,032
|
|
|
|
189
|
|
Deferred charges and other
|
|
|
762
|
|
|
|
510
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
43,425
|
|
|
$
|
28,186
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
779
|
|
|
$
|
397
|
|
Accrued operating expense
|
|
|
163
|
|
|
|
90
|
|
Accrued exploration and development
|
|
|
1,367
|
|
|
|
923
|
|
Accrued compensation and benefits
|
|
|
231
|
|
|
|
152
|
|
Current debt
|
|
|
46
|
|
|
|
117
|
|
Asset retirement obligations
|
|
|
407
|
|
|
|
147
|
|
Derivative instruments
|
|
|
194
|
|
|
|
128
|
|
Other
|
|
|
337
|
|
|
|
439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,524
|
|
|
|
2,393
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT
|
|
|
8,095
|
|
|
|
4,950
|
|
|
|
|
|
|
|
|
|
|
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Income taxes
|
|
|
4,249
|
|
|
|
2,765
|
|
Asset retirement obligation
|
|
|
2,465
|
|
|
|
1,637
|
|
Other
|
|
|
715
|
|
|
|
662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,429
|
|
|
|
5,064
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
SHAREHOLDERS EQUITY:
|
|
|
|
|
|
|
|
|
Preferred stock, no par value, 5,000,000 shares authorized,
6% Cumulative Mandatory Convertible, Series D, $1,000 per
share liquidation preference, 1,265,000 shares issued and
outstanding in 2010
|
|
|
1,227
|
|
|
|
|
|
Common stock, $0.625 par, 430,000,000 shares
authorized, 383,668,297 and 344,076,790 shares issued,
respectively
|
|
|
240
|
|
|
|
215
|
|
Paid-in capital
|
|
|
8,864
|
|
|
|
4,634
|
|
Retained earnings
|
|
|
14,223
|
|
|
|
11,437
|
|
Treasury stock, at cost, 1,276,555 and 7,639,818 shares,
respectively
|
|
|
(36
|
)
|
|
|
(217
|
)
|
Accumulated other comprehensive loss
|
|
|
(141
|
)
|
|
|
(290
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
24,377
|
|
|
|
15,779
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
43,425
|
|
|
$
|
28,186
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes to consolidated financial statements are
an integral part of this statement.
F-6
APACHE
CORPORATION AND SUBSIDIARIES
STATEMENT
OF CONSOLIDATED SHAREHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
Series B
|
|
|
Series D
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
Total
|
|
|
|
Comprehensive
|
|
|
|
Preferred
|
|
|
Preferred
|
|
|
Common
|
|
|
Paid-In
|
|
|
Retained
|
|
|
Treasury
|
|
|
Comprehensive
|
|
|
Shareholders
|
|
|
|
Income (Loss)
|
|
|
|
Stock
|
|
|
Stock
|
|
|
Stock
|
|
|
Capital
|
|
|
Earnings
|
|
|
Stock
|
|
|
Income (Loss)
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2007
|
|
|
|
|
|
|
$
|
98
|
|
|
$
|
|
|
|
$
|
213
|
|
|
$
|
4,367
|
|
|
$
|
11,458
|
|
|
$
|
(238
|
)
|
|
$
|
(520
|
)
|
|
$
|
15,378
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
712
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
712
|
|
|
|
|
|
|
|
|
|
|
|
712
|
|
Postretirement, net of income tax benefit of $7
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8
|
)
|
|
|
(8
|
)
|
Commodity hedges, net of income tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
expense of $301
|
|
|
550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
550
|
|
|
|
550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
1,254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
Common ($.70 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(234
|
)
|
|
|
|
|
|
|
|
|
|
|
(234
|
)
|
Common shares issued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38
|
|
Treasury shares issued, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
10
|
|
Compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2008
|
|
|
|
|
|
|
|
98
|
|
|
|
|
|
|
|
214
|
|
|
|
4,473
|
|
|
|
11,930
|
|
|
|
(228
|
)
|
|
|
22
|
|
|
|
16,509
|
|
Comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(285
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(285
|
)
|
|
|
|
|
|
|
|
|
|
|
(285
|
)
|
Postretirement, net of income tax benefit of $5
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
(4
|
)
|
Commodity hedges, net of income tax benefit of $171
|
|
|
(308
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(308
|
)
|
|
|
(308
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss
|
|
$
|
(597
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
(7
|
)
|
Common ($.60 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(201
|
)
|
|
|
|
|
|
|
|
|
|
|
(201
|
)
|
Preferred stock redemption
|
|
|
|
|
|
|
|
(98
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(98
|
)
|
Common shares issued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
Treasury shares issued, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
6
|
|
Compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
128
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
215
|
|
|
|
4,634
|
|
|
|
11,437
|
|
|
|
(217
|
)
|
|
|
(290
|
)
|
|
|
15,779
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
3,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,032
|
|
|
|
|
|
|
|
|
|
|
|
3,032
|
|
Postretirement, net of income tax expense of $2
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
(2
|
)
|
Commodity hedges, net of income tax expense of $62
|
|
|
151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
151
|
|
|
|
151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
3,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(32
|
)
|
|
|
|
|
|
|
|
|
|
|
(32
|
)
|
Common ($.60 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(214
|
)
|
|
|
|
|
|
|
|
|
|
|
(214
|
)
|
Mandatory convertible preferred stock issued
|
|
|
|
|
|
|
|
|
|
|
|
1,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,227
|
|
Common stock issuance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
|
|
|
|
3,969
|
|
|
|
|
|
|
|
170
|
|
|
|
|
|
|
|
4,163
|
|
Common stock activity, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
|
|
Treasury stock activity, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
12
|
|
Compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
225
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2010
|
|
|
|
|
|
|
$
|
|
|
|
$
|
1,227
|
|
|
$
|
240
|
|
|
$
|
8,864
|
|
|
$
|
14,223
|
|
|
$
|
(36
|
)
|
|
$
|
(141
|
)
|
|
$
|
24,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes to consolidated financial statements are
an integral part of this statement.
F-7
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nature
of Operations
Apache Corporation (Apache or the Company) is an oil and gas
exploration and production company with operations in seven
countries, spanning five continents: the United States, Canada,
Egypt, the U.K. North Sea, Australia, Argentina and on the
Chilean side of the island of Tierra del Fuego.
|
|
1.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Accounting policies used by Apache and its subsidiaries reflect
industry practices and conform to accounting principles
generally accepted in the U.S. (GAAP). Certain
reclassifications have been made to prior periods to conform to
current-year presentation. Significant policies are discussed
below.
Principles
of Consolidation
The accompanying consolidated financial statements include the
accounts of Apache and its subsidiaries after elimination of
intercompany balances and transactions. The Companys
interest in oil and gas exploration and production ventures and
partnerships are proportionately consolidated. The Company
consolidates all investments in which the Company, either
through direct or indirect ownership, has more than a 50-percent
voting interest.
Use of
Estimates
Preparation of financial statements in conformity with GAAP and
disclosure of contingent assets and liabilities requires
management to make estimates and assumptions that affect
reported amounts of assets and liabilities at the date of the
financial statements and the reported amounts of revenues and
expenses during the reporting period. The Company bases its
estimates on historical experience and various other assumptions
that are believed to be reasonable under the circumstances, the
results of which form the basis for making judgments about
carrying values of assets and liabilities that are not readily
apparent from other sources. Apache evaluates its estimates and
assumptions on a regular basis. Actual results may differ from
these estimates and assumptions used in preparation of its
financial statements and changes in these estimates are recorded
when known. Significant estimates made in preparing these
financial statements include fair value of acquired assets and
liabilities (see Note 2 Acquisitions), the
estimate of proved oil and gas reserves and related present
value estimates of future net cash flows therefrom (see
Note 12 Supplemental Oil and Gas Disclosures),
asset retirement obligations (see Note 4 Asset
Retirement Obligation) and income taxes (see
Note 6 Income Taxes).
Cash
Equivalents
The Company considers all highly liquid short-term investments
with a maturity of three months or less at the time of purchase
to be cash equivalents. These investments are carried at cost,
which approximates fair value. As of December 31, 2010 and
2009, Apache had $134 million and $2.0 billion,
respectively, of cash and cash equivalents.
Accounts
Receivable and Allowance for Doubtful Accounts
Accounts receivable are stated at the historical carrying amount
net of write-offs and allowance for uncollectible accounts. The
carrying amount of Apaches accounts receivable approximate
fair value because of the short-term nature of the instruments.
The Company routinely assesses the collectability of all
material trade and other receivables. Many of Apaches
receivables are from joint interest owners on properties Apache
operates. The Company may have the ability to withhold future
revenue disbursements to recover any non-payment of these joint
interest billings. The Company accrues a reserve on a receivable
when, based on the judgment of management, it is probable that a
receivable will not be collected and the amount of any reserve
may be reasonably estimated. As of December 31, 2010 and
2009, the Company had an allowance for doubtful accounts of
$48 million and $38 million, respectively.
F-8
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Inventories
Inventories consist principally of tubular goods and equipment,
stated at the weighted-average cost, and oil produced but not
sold, stated at the lower of cost or market.
Oil
and Gas Property
The Company uses the full-cost method of accounting for its
exploration and development activities. Under this method of
accounting, the cost of both successful and unsuccessful
exploration and development activities are capitalized as
property and equipment. This includes any internal costs that
are directly related to exploration and development activities,
including salaries and benefits, but does not include any costs
related to production, general corporate overhead or similar
activities. Historically, total capitalized internal costs in
any given year have not been material to total oil and gas costs
capitalized in such year. Apache capitalized $321 million,
$219 million and $236 million of these internal costs
in 2010, 2009 and 2008, respectively. Proceeds from the sale or
disposition of oil and gas properties are accounted for as a
reduction to capitalized costs unless a significant portion
(greater than 25 percent) of the Companys reserve
quantities in a particular country are sold, in which case a
gain or loss is recognized in income.
Costs
Excluded
Oil and gas unevaluated properties and properties under
development include costs that are excluded from costs being
depreciated or amortized. These costs represent investments in
unproved properties and major development projects in which the
Company owns a direct interest. Apache excludes these costs on a
country-by-country
basis until proved reserves are found, until it is determined
that the costs are impaired or until major development projects
are placed in service. All costs excluded are reviewed at least
quarterly to determine if impairment has occurred. In countries
where proved reserves exist, exploratory drilling costs
associated with dry holes are transferred to proved properties
immediately upon determination that a well is dry and amortized
accordingly. Also, geological and geophysical costs not
associated with specific properties are recorded to proved
property. For international operations where a reserve base has
not yet been established, impairments are charged to earnings
and are determined through an evaluation considering, among
other factors, seismic data, requirements to relinquish acreage,
drilling results, remaining time in the commitment period,
remaining capital plan and political, economic and market
conditions.
Ceiling
Test
Under the existing full-cost method of accounting, a ceiling
test is performed each quarter. The test establishes a limit
(ceiling), on a
country-by-country
basis, on the book value of oil and gas properties. The
capitalized costs of proved oil and gas properties, net of
accumulated depreciation, depletion and amortization (DD&A)
and the related deferred income taxes, may not exceed this
ceiling. The ceiling limitation is the estimated
after-tax future net cash flows from proved oil and gas
reserves, excluding future cash outflows associated with
settling asset retirement obligations accrued on the balance
sheet. If capitalized costs exceed this ceiling, the excess is
charged to expense and reflected as additional DD&A in the
accompanying statement of consolidated operations.
Effective December 31, 2009, Apache adopted revised oil and
gas disclosure requirements set forth by the
U.S. Securities and Exchange Commission (SEC) in Release
No. 33-8995,
Modernization of Oil and Gas Reporting and as
codified by the Financial Accounting Standards Board (FASB) in
Accounting Standards Codification (ASC) Topic 932,
Extractive Industries Oil and Gas. The
new rules include changes to the pricing used to estimate
reserves, the option to disclose probable and possible reserves,
revised definitions for proved reserves, additional disclosures
with respect to undeveloped reserves, and other new or revised
definitions and disclosures.
F-9
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The estimate of after-tax future net cash flows as of
December 31, 2010 and 2009 is calculated using a discount
rate of 10 percent per annum,
end-of-period
costs, and an unweighted arithmetic average of commodity prices
in effect on the first day of each month in 2010 and 2009, held
flat for the life of the production, except where prices are
defined by contractual arrangements. Prior to adoption of the
Modernization Rules, effective in the fourth quarter of 2009,
estimated after-tax future net cash flows were calculated using
commodity prices in effect at the end of each quarter.
As of December 31, 2010, capitalized costs did not exceed
the ceiling limitation, and no write-down was indicated.
Excluding the effect of cash flow hedges in calculating the
ceiling limitation at December 31, 2010, capitalized costs
still would not have exceeded the ceiling limitation. See
Note 12 Supplemental Oil and Gas Disclosures
for a discussion of the calculation of estimated future net cash
flows.
Under then-existing full-cost accounting rules, the Company
recorded a $5.3 billion ($3.6 billion net of tax)
non-cash write-down of the carrying value of the Companys
U.S., U.K. North Sea, Canadian and Argentine proved oil and gas
properties on December 31, 2008, as a result of the ceiling
test limitations. Under those same rules, which were in effect
for the first three quarterly reporting periods in 2009, the
Company recorded an additional $2.82 billion
($1.98 billion net of tax) non-cash write-down of the
carrying value of the Companys U.S. and Canadian
proved oil and gas properties as of March 31, 2009. These
write-downs are reflected as additional DD&A expense in the
accompanying statement of consolidated operations. Excluding the
effects of cash flow hedges in calculating the ceiling
limitation, the write-downs as of December 31, 2008 and
March 31, 2009 would have been $5.9 billion
($4.0 billion net of tax) and $3.4 billion
($2.4 billion net of tax), respectively.
Gathering,
Transmission and Processing Facilities
The Company assesses the carrying amount of its gathering,
transmission and processing facilities annually and whenever
events or changes in circumstances indicate that their carrying
amount may not be recoverable. If the carrying amount of these
facilities is less than the sum of the undiscounted cash flows
expected to result from their use and eventual disposition, an
impairment loss is recorded through a charge to expense.
Gathering, transmission and processing facilities totaled
$4.2 billion and $3.2 billion at December 31,
2010 and 2009, respectively. No impairment of gathering,
transmission and processing facilities was recognized during
2010, 2009 or 2008.
Depreciation,
Depletion and Amortization
DD&A of oil and gas properties is calculated quarterly, on
a
country-by-country
basis, using the Units of Production Method (UOP). The UOP
calculation, in its simplest terms, multiplies the percentage of
estimated proved reserves produced each quarter times the cost
of those reserves. The result is to recognize expense at the
same pace that the reservoirs are actually depleting. The
amortization base in the UOP calculation includes the sum of
proved property costs net of accumulated DD&A, estimated
future development costs (future costs to access and develop
reserves) and asset retirement costs that are not already
included in oil and gas property, less related salvage value.
Gas gathering, transmission and processing facilities, buildings
and equipment are depreciated on a straight-line basis over the
estimated useful lives of the assets, which range from three to
20 years. Accumulated depreciation for these assets totaled
$1.3 billion and $1.1 billion at December 31,
2010 and 2009, respectively.
Asset
Retirement Obligation
The initial estimated asset retirement obligation (ARO) related
to properties is recognized as a liability, with an associated
increase in property and equipment for the asset retirement
cost. Accretion expense is recognized over the estimated
productive life of the related assets. If the fair value of the
estimated ARO changes, an adjustment is recorded to both the ARO
and the asset retirement cost. Revisions in estimated
liabilities can result from changes in
F-10
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
estimated inflation rates, changes in service and equipment
costs and changes in the estimated timing of settling ARO.
Capitalized
Interest
Interest is capitalized on oil and gas investments in unproved
properties and in-progress exploration and development
activities. Major construction projects also qualify for
interest capitalization up until the time the assets are ready
for service. Capitalized interest is calculated by multiplying
the Companys weighted-average interest rate on debt by the
amount of qualifying costs. For projects under construction that
carry their own financing, interest is calculated using the
interest rate related to the project financing. Interest and
related costs are capitalized until each project is complete.
Capitalized interest cannot exceed gross interest expense.
Capitalized interest associated with unproved properties is
transferred to proved properties along with the associated
unproved property balance. When major construction projects are
completed, the associated capitalized interest is amortized over
the useful life of the related asset. Capitalized interest
totaled $120 million, $61 million and $94 million
in 2010, 2009 and 2008, respectively.
Business
Combinations
Apache records all business combinations in accordance with ASC
Topic 805, Business Combinations. A business
combination includes all transactions or other events in which
control of one or more businesses is obtained. ASC Topic 805
requires the recognition and measurement of identifiable assets
acquired and liabilities assumed and recording deferred taxes
for any differences between the fair values of net assets
acquired and carryover tax basis of assets and liabilities. Any
excess of the purchase price over the estimated fair values of
assets and liabilities is recorded as goodwill.
Purchase
Price Allocation
The purchase price allocation is accomplished by recording each
asset and liability at its estimated fair value. Estimated
deferred taxes are based on available information concerning the
tax basis of the acquired companys assets and liabilities
and tax-related carryforwards at the merger date. The final
determination of fair value for certain assets and liabilities
will be completed as soon as the information necessary to
complete the analysis is obtained. These amounts will be
finalized as soon as possible, but no later than one year from
the acquisition date. The amount of goodwill recorded in any
particular business combination can vary significantly depending
upon the values attributed to assets acquired and liabilities
assumed relative to the total acquisition cost.
Goodwill
Goodwill represents the excess of the consideration transferred
over the net assets recognized and represents the future
economic benefits arising from assets acquired that could not be
individually identified and separately recognized. The Company
assesses the carrying amount of goodwill by testing the goodwill
for impairment annually and when impairment indicators arise.
The impairment test requires allocating goodwill and all other
assets and liabilities to assigned reporting units. The fair
value of each unit is determined as of the date of the
impairment test and compared to the book value of the reporting
unit. If the fair value of the reporting unit is less than the
book value, including goodwill, then goodwill is written down to
the implied fair value of the goodwill through a charge to
expense. Goodwill totaled $1.0 billion and
$189 million at December 31, 2010 and 2009,
respectively. Goodwill of $843 million was recorded in the
U.S. in 2010 as a result of the merger with Mariner Energy,
Inc. (Mariner), as discussed in Note 2
Acquisitions. As of December 31, 2010 and 2009,
approximately $103 million and $86 million were
recorded in Canada and Egypt, respectively. Each country was
assessed as a reporting unit. No impairment of goodwill was
recognized during 2010, 2009 or 2008.
F-11
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Accounts
Payable
Included in accounts payable at December 31, 2010 and 2009,
are liabilities of approximately $191 million and
$98 million, respectively, representing the amount by which
checks issued, but not presented to the Companys banks for
collection, exceeded balances in applicable bank accounts.
Commitments
and Contingencies
Accruals for loss contingencies arising from claims,
assessments, litigation, environmental and other sources are
recorded when it is probable that a liability has been incurred
and the amount can be reasonably estimated. These accruals are
adjusted as additional information becomes available or
circumstances change.
Revenue
Recognition and Imbalances
Oil and gas revenues are recognized when production is sold to a
purchaser at a fixed or determinable price, when delivery has
occurred and title has transferred, and if collectibility of the
revenue is probable. Cash received relating to future revenues
is deferred and recognized when all revenue recognition criteria
are met.
Apache uses the sales method of accounting for gas production
imbalances. The volumes of gas sold may differ from the volumes
to which Apache is entitled based on its interests in the
properties. These differences create imbalances that are
recognized as a liability only when the properties
estimated remaining reserves net to Apache will not be
sufficient to enable the under-produced owner to recoup its
entitled share through production. The Companys recorded
liability is generally reflected in other non-current
liabilities. No receivables are recorded for those wells where
Apache has taken less than its share of production. Gas
imbalances are reflected as adjustments to estimates of proved
gas reserves and future cash flows in the unaudited supplemental
oil and gas disclosures.
Apache markets its own U.S. natural gas production. Since
the Companys production fluctuates because of operational
issues, it is occasionally necessary to purchase gas
(third-party gas) to fulfill sales obligations and commitments.
Both the costs and sales proceeds of this third-party gas are
reported on a net basis in oil and gas production revenues. The
costs of third-party gas netted against the related sales
proceeds totaled $33 million, $34 million and
$56 million, for 2010, 2009 and 2008, respectively.
The Companys Egyptian operations are conducted pursuant to
production sharing contracts under which contractor partners pay
all operating and capital costs for exploring and developing the
concessions. A percentage of the production, generally up to
40 percent, is available to contractor partners to recover
these operating and capital costs over contractually defined
terms. Cost recovery is reflected in revenue. The balance of the
production is split among the contractor partners and the
Egyptian General Petroleum Corporation (EGPC) on a contractually
defined basis.
Derivative
Instruments and Hedging Activities
Apache periodically enters into derivative contracts to manage
its exposure to commodity price risk. These derivative
contracts, which are generally placed with major financial
institutions that the Company believes are minimal credit risks,
may take the form of forward contracts, futures contracts, swaps
or options. The oil and gas reference prices, upon which the
commodity derivative contracts are based, reflect various market
indices that have a high degree of historical correlation with
actual prices received by the Company for its oil and gas
production.
Apache accounts for its derivative instruments in accordance
with ASC Topic 815, Derivatives and Hedging, which
requires that all derivative instruments, other than those that
meet the normal purchases and sales exception, be recorded on
the balance sheet as either an asset or liability measured at
fair value. Changes in fair value are recognized currently in
earnings unless specific hedge accounting criteria are met.
Hedge accounting treatment allows unrealized gains and losses on
cash flow hedges to be deferred in other comprehensive income.
Realized gains and losses from the Companys oil and gas
cash flow hedges, including terminated contracts, are generally
F-12
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
recognized in oil and gas production revenues when the
forecasted transaction occurs. Gains and losses from the change
in fair value of derivative instruments that do not qualify for
hedge accounting are reported in current-period income as
Other under Revenues and Other in the statement of
consolidated operations. If at any time the likelihood of
occurrence of a hedged forecasted transaction ceases to be
probable, hedge accounting treatment will cease on a
prospective basis, and all future changes in the fair value of
the derivative will be recognized directly in earnings. Amounts
recorded in other comprehensive income prior to the change in
the likelihood of occurrence of the forecasted transaction will
remain in other comprehensive income until such time as the
forecasted transaction impacts earnings. If it becomes probable
that the original forecasted production will not occur, then the
derivative gain or loss would be reclassified from accumulated
other comprehensive income into earnings immediately. Hedge
effectiveness is measured at least quarterly based on the
relative changes in fair value between the derivative contract
and the hedged item over time, and any ineffectiveness is
immediately reported as Other under Revenues and
Other in the statement of consolidated operations.
General
and Administrative Expense
General and administrative expenses are reported net of
recoveries from owners in properties operated by Apache and net
of amounts related to lease operating activities or capitalized
pursuant to the full-cost method of accounting.
Income
Taxes
Apache records deferred tax assets and liabilities to account
for the expected future tax consequences of events that have
been recognized in the financial statements and tax returns. The
Company routinely assesses the realizability of its deferred tax
assets. If the Company concludes that it is more likely than not
that some or all of the deferred tax assets will not be realized
under accounting standards, the tax asset is reduced by a
valuation allowance. Numerous judgments and assumptions are
inherent in the determination of future taxable income,
including factors such as future operating conditions
(particularly as related to prevailing oil and gas prices) and
changing tax laws.
Earnings from Apaches international operations are
permanently reinvested; therefore, the Company does not
recognize U.S. deferred taxes on the unremitted earnings of
its international subsidiaries. If it becomes apparent that some
or all of the unremitted earnings will be remitted, the Company
will then recognize taxes on those earnings.
Foreign
Currency Translation
The U.S. dollar is the functional currency for each of
Apaches international operations. The functional currency
is determined
country-by-country
based on relevant facts and circumstances of the cash flows,
commodity pricing environment and financing arrangements in each
country. Foreign currency translation gains and losses arise
when monetary assets and liabilities denominated in foreign
currencies are remeasured to their U.S. dollar equivalent
at the exchange rate in effect at the end of each reporting
period.
The Company accounts for foreign currency gains and losses in
accordance with ASC Topic 830, Foreign Currency
Matters. Foreign currency translation gains and losses
related to current taxes payable and deferred tax liabilities
are recorded as a component of provision for income taxes. In
2010, the Company recorded additional net tax expense of
$111 million, including a current tax expense of
$2 million and deferred tax expense of $109 million,
in connection with foreign currency translation gains and
losses. Included in deferred tax expense for 2010 is
approximately $57 million of tax expense attributable to
realized foreign currency transactions. In 2009, Apache recorded
an additional net tax expense of $195 million, including a
current benefit of $3 million and a deferred expense of
$198 million. In 2008, Apache recorded an additional tax
benefit of $400 million, including a current benefit of
$3 million and a deferred benefit of $397 million. For
further discussion, see Note 6 Income Taxes.
All other foreign currency translation gains and losses are
reflected in Other under Revenues and Other in the
statement of consolidated operations. The Companys other
foreign currency gains and losses included in Other
F-13
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
under Revenues and Other in the statement of consolidated
operations netted to a loss in 2010 of $39 million, and
gains of $11 million and $38 million in 2009 and 2008,
respectively.
Foreign currency gains and losses also arise when revenue and
disbursement transactions denominated in a countrys local
currency are converted to a U.S. dollar equivalent based on
the average exchange rates during the reporting period.
Insurance
Coverage
The Company recognizes an insurance receivable when collection
of the receivable is deemed probable. Any recognition of an
insurance receivable is recorded by crediting and offsetting the
original charge. Any differential arising between insurance
recoveries and insurance receivables is recorded as a
capitalized cost or as an expense, consistent with its original
treatment.
Earnings
Per Share
The Companys basic earnings per share (EPS) amounts have
been computed based on the weighted-average number of shares of
common stock outstanding for the period. Diluted EPS reflects
the potential dilution, using the treasury stock method, which
assumes that options were exercised and restricted stock was
fully vested.
Diluted EPS also includes the impact of unvested share
appreciation plans. For awards in which the share price goals
have already been achieved, shares are included in diluted EPS
using the treasury stock method. For those awards in which the
share price goals have not been achieved, the number of
contingently issuable shares included in diluted EPS is based on
the number of shares, if any, using the treasury stock method,
that would be issuable if the market price of the Companys
stock at the end of the reporting period exceeded the share
price goals under the terms of the plan. The diluted EPS
calculation also includes additional shares of common stock from
the assumed conversion of Apaches convertible preferred
stock.
Stock-Based
Compensation
The Company accounts for stock-based compensation under the fair
value recognition provisions of ASC Topic 718,
Compensation Stock Compensation. The
Company grants various types of stock-based awards including
stock options, nonvested restricted stock units and
performance-based awards. In 2003 and 2004, the Company also
granted cash-based stock appreciation rights. These plans and
related accounting policies are defined and described more fully
in Note 7 Capital Stock. Stock compensation
awards granted are valued on the date of grant and are expensed,
net of estimated forfeitures, over the required service period.
ASC Topic 718 also requires that benefits of tax deductions in
excess of recognized compensation cost be reported as financing
cash flows rather than as operating cash flows. The Company
classified $28 million, $16 million and
$47 million as financing cash inflows in 2010, 2009 and
2008, respectively.
Treasury
Stock
The Company follows the weighted-average-cost method of
accounting for treasury stock transactions.
Recently
Issued Accounting Standards Not Yet Adopted
All new accounting pronouncements previously issued have been
adopted as of or prior to December 31, 2010.
F-14
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2010
Activity
Kitimat
LNG Project
During the first quarter of 2010 Apache Canada Ltd. (Apache
Canada), through its subsidiaries, purchased a
51-percent
interest in a planned LNG export terminal (Kitimat LNG facility)
and a 25.5-percent interest in a partnership that owns a related
proposed pipeline. In the second quarter of 2010 EOG Resources
Canada, Inc. (EOG Canada), through its wholly-owned
subsidiaries, acquired the remaining 49 percent of the
Kitimat LNG facility and a 24.5-percent interest in the pipeline
partnership. In February 2011 Apache Canada and EOG Canada
entered into an agreement to purchase the remaining 50-percent
interest in the pipeline partnership from Pacific Northern Gas
Ltd (PNG). Under the terms of the agreement, PNG will operate
and maintain the planned pipeline under a seven-year agreement
with Apache Canada and EOG Canada with provisions for five-year
renewals. It also includes a
20-year
transportation service arrangement which may require Apache
Canada and EOG Canada, under certain circumstances, to use a
portion of PNGs current pipeline capacity. Upon close of
the transaction, expected in the second quarter of 2011, Apache
Canada and EOG Canada will own 51 percent and
49 percent, respectively, of the proposed pipeline.
Apache Canada and EOG Canada plan to build the Kitimat LNG
facility on Bish Cove near the Port of Kitimat, 400 miles
north of Vancouver, British Columbia. The facility is planned
for an initial minimum capacity of
700 MMcf/d,
or five million metric tons of LNG per year, of which Apache
Canada has reserved 51 percent. The proposed
287-mile
pipeline will originate in Summit Lake, British Columbia, and is
designed to link the Kitimat LNG facility to the pipeline system
currently servicing western Canadas natural gas producing
regions. Apache Canada will have rights to 51-percent of the
capacity in the proposed pipeline. Completion of the FEED study
and a final investment decision are targeted for late 2011.
Construction is expected to commence in 2012, with commercial
operations projected to begin in 2015.
Gulf
of Mexico Shelf Acquisition
On June 9, 2010, Apache completed an acquisition of oil and
gas assets on the Gulf of Mexico shelf from Devon Energy
Corporation (Devon) for $1.05 billion, subject to normal
post-closing adjustments. The acquisition was effective
January 1, 2010. The acquired assets include
477,000 net acres across 150 blocks and estimated proved
reserves of 41 million barrels of oil equivalent (MMboe)
(unaudited). Approximately half of the estimated net proved
reserves were liquid hydrocarbons, and seven major fields
account for 90 percent of the estimated proved reserves.
Virtually all of the production is located in fields in water
depths less than 500 feet, and Apache now operates
75 percent of the production. Apache allocated
$653 million of the purchase price to proved property,
$361 million to unproved property and $4 million to
gas plant facilities. Apache also recorded abandonment
obligations for the properties of $233 million. The
acquisition was funded primarily from existing cash balances.
Mariner
Energy, Inc. Merger
On November 10, 2010, Apache acquired Mariner, an
independent exploration and production company, in a stock and
cash transaction. Mariners assets and liabilities are
reflected in Apaches financial statements at fair value.
Mariners oil and gas properties are primarily located in
the Gulf of Mexico deepwater and shelf, the Permian Basin and
onshore in the Gulf Coast. The Permian Basin and Gulf of Mexico
shelf assets are complementary to Apaches existing
holdings and provide an inventory of future potential drilling
locations, particularly in the Spraberry and Wolfcamp formation
oil plays of the Permian Basin. Additionally, Mariner has
accumulated acreage in emerging unconventional shale oil
resources in the U.S.
F-15
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The total amount of cash and shares of Apache common stock paid
and issued, respectively, pursuant to the Merger Agreement was
fixed, and Mariner stockholders received (on an aggregate basis)
0.17043 of a share of Apache common stock, par value $0.625 per
share, and $7.80 in cash for each share of Mariner common stock,
with cash being paid in lieu of any fractional shares of Apache
common stock. Upon completion of the Merger, each outstanding
employee option to purchase Mariner common stock was converted
into a fully vested option to purchase 0.24347 shares of
Apache common stock.
Excluded from consideration was $4 million and
approximately 100,000 shares of Apache common stock issued
in exchange for 40 percent of Mariner employee
performance-based restricted shares, which was recognized in
merger, acquisitions and transition expense in the statement of
consolidated operations.
The components of the consideration transferred follow:
|
|
|
|
|
|
|
(In millions)
|
|
|
Cash consideration
|
|
$
|
787
|
|
Consideration attributable to stock issued(1)
|
|
|
1,896
|
|
Consideration attributable to converted stock options(2)
|
|
|
8
|
|
|
|
|
|
|
Total consideration transferred
|
|
$
|
2,691
|
|
|
|
|
|
|
|
|
|
(1) |
|
The fair value of Apaches common stock on the acquisition
date was $110.25 per share based on the closing value on the
NYSE. Apache issued 17.2 million shares of Apache common
stock in exchange for Mariner common and restricted stock as
part of consideration. |
|
(2) |
|
On the effective date of the merger, Apache exchanged 145,438
stock options for options held by Mariner employees with a fair
value of $8 million, determined using the Black-Scholes
option pricing model. |
Recording
of Assets Acquired and Liabilities Assumed
The transaction was accounted for using the acquisition method
of accounting, which requires, among other things, that assets
acquired and liabilities assumed be recognized at their fair
values as of the acquisition date.
The
following table summarizes the preliminary estimates of the
assets acquired and liabilities assumed in the merger. The final
determination of fair value for certain assets and liabilities
will be completed as soon as the information necessary to
complete the analysis is obtained. These amounts will be
finalized as soon as possible, but no later than one year from
the acquisition date.
|
|
|
|
|
|
|
(In millions)
|
|
|
Current assets
|
|
$
|
172
|
|
Property, plant and equipment
|
|
|
4,523
|
|
Goodwill(1)
|
|
|
843
|
|
Other assets
|
|
|
44
|
|
|
|
|
|
|
Total assets acquired
|
|
$
|
5,582
|
|
|
|
|
|
|
Current liabilities
|
|
|
158
|
|
Long-term debt(2)
|
|
|
1,656
|
|
Asset retirement obligation
|
|
|
537
|
|
Deferred income tax liabilities
|
|
|
509
|
|
Other long-term obligations
|
|
|
31
|
|
|
|
|
|
|
Total liabilities assumed
|
|
$
|
2,891
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
2,691
|
|
|
|
|
|
|
|
|
|
(1) |
|
Goodwill was the excess of the consideration transferred over
the net assets recognized and represents the future economic
benefits arising from assets acquired that could not be
individually identified and separately
|
F-16
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
recognized. Goodwill is not amortized and is not deductible for
tax purposes, but is subject to an impairment test annually and
when other impairment conditions arise. |
|
(2) |
|
Long-term debt was recognized based on market rates on the date
of closing (Level 2). Long-term debt at closing was as follows: |
|
|
|
|
|
Bank debt:
|
|
(In millions)
|
|
|
Revolving Credit Facility
|
|
$
|
632
|
|
Senior notes:
|
|
|
|
|
7.5% due 2013 includes premium of $10 million
|
|
|
310
|
|
11.75% due 2016 includes premium of $81 million
|
|
|
381
|
|
8% due 2017 includes premium of $33 million
|
|
|
333
|
|
|
|
|
|
|
Total Long-term debt
|
|
$
|
1,656
|
|
|
|
|
|
|
Outstanding bank facility borrowings of $632 million were
repaid immediately following closing through borrowings under
Apaches commercial paper facility. During the fourth
quarter of 2010, all remaining assumed debt was repaid with net
proceeds from the issuance of new debt, as discussed further in
Note 5 Debt, and with existing cash balances.
BP
Acquisitions
In July 2010 Apache entered into three definitive purchase and
sale agreements to acquire the properties described below from
subsidiaries of BP plc (collectively referred to as
BP) for aggregate consideration of
$7.0 billion, subject to customary adjustments. The
effective date of the transactions was July 1, 2010.
Preferential purchase rights for approximately $658 million
of the value of the BP properties in the Permian Basin were
exercised, and accordingly, the purchase price for the BP
properties was reduced to approximately $6.4 billion,
subject to normal post-closing adjustments.
Permian
Basin
On August 10, 2010, Apache completed the acquisition of
BPs oil and gas operations, related infrastructure and
acreage in the Permian Basin of west Texas and New Mexico. The
acquired assets, net of preferential purchase rights exercised,
include interests in several field areas, including
Block 16/Coy Waha, Brown Basset, Empire/Yeso, Pegasus,
Southeast Lea, Spraberry, Wilshire, and Delaware Penn,
approximately 405,000 net mineral and fee acres,
approximately 351,000 leasehold acres and three gas processing
plants. The Permian Basin assets had estimated net proved
reserves of 124 MMboe (unaudited) (64 percent liquid
hydrocarbons, or liquids) as of the effective date.
The
agreed-upon
purchase price of $3.1 billion was reduced by
$658 million for the exercise of preferential rights to
purchase. Apache allocated $2.0 billion of the purchase
price to proved property, $259 million to unproved property
and $183 million to gas plant facilities. Apache also
recorded abandonment obligations for the properties of
$19 million and a reserve for environmental remediation of
$11 million. BP continued to operate the properties on
Apaches behalf through November 30, 2010.
Western
Canada Sedimentary Basin
On October 8, 2010, Apache completed the acquisition of
substantially all of BPs Western Canadian upstream natural
gas assets, including approximately 1,278,000 net mineral
and leasehold acres, interests in approximately 1,800 active
wells and eight operated and 15 non-operated gas processing
plants. The position includes many drilling opportunities
ranging from conventional to several unconventional targets,
such as shale gas, tight gas and coal bed methane in
historically productive formations including the Montney,
Cadomin and Doig. These properties had estimated net proved
reserves of 224 MMboe (unaudited) (94 percent gas) as
of the effective date. The purchase price was
$3.25 billion, subject to normal post-closing adjustments.
Apache allocated $2.7 billion of the purchase price to
F-17
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
proved property, $533 million to unproved property and
$150 million to gas plant facilities. Apache also recorded
abandonment obligations for the properties of $58 million
and a reserve for environmental remediation of $98 million.
Western
Desert, Egypt
On November 4, 2010, Apache completed the acquisition of
BPs interests in four development licenses and one
exploration concession (East Badr El Din) in the Western Desert
of Egypt. These properties, covering 394,000 net acres
south of El Alamein, are operated by Gulf of Suez Petroleum
Company, a joint venture between BP and the Government of Egypt.
The transaction includes BPs interests in 65 active wells,
a 24-inch
gas line, a liquefied petroleum gas plant in Dashour, a gas
processing plant in Abu Gharadig and a portion of a
12-inch oil
export line to the El Hamra Terminal on the Mediterranean Sea.
These properties had estimated net proved reserves of
20 MMboe (unaudited) (59 percent liquids) as of the
effective date. The merged concession agreement related to the
development licenses runs through 2024, subject to a five-year
extension at the option of the operator. The purchase price was
$650 million, subject to normal post-closing adjustments.
Apache allocated $325 million of the purchase price to
proved property, $145 million to unproved property and
$150 million to gas plant facilities.
The Company financed the purchase of properties from BP by
issuing a combination of common stock and mandatory convertible
preferred shares, raising net proceeds of $3.5 billion;
securing a bridge loan facility; issuing new term debt and
commercial paper; and using existing cash balances. For further
discussion of these debt instruments and equity issuances,
please see Note 5 Debt and
Note 7 Capital Stock, respectively.
Actual
and Pro Forma Impact of Acquisitions (Unaudited)
Revenues attributable to the Devon acquisition, BP acquisitions
and Mariner merger included in Apaches statement of
consolidated operations for the year ended December 31,
2010, were $197 million, $308 million and
$95 million, respectively. Direct expenses attributable to
the acquisitions and merger included in the statement of
consolidated operations for the same period were
$39 million, $78 million and $26 million,
respectively.
The following table presents pro forma information for Apache as
if the acquisition of properties from Devon and BP and the
Mariner merger occurred on January 1, 2009:
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In millions, except per share amounts)
|
|
|
Revenues and Other
|
|
$
|
13,780
|
|
|
$
|
10,717
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
$
|
3,364
|
|
|
$
|
(477
|
)
|
Preferred Stock Dividends
|
|
|
76
|
|
|
|
83
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Attributable to Common Stock
|
|
|
3,288
|
|
|
|
(560
|
)
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) per Common Share Basic
|
|
$
|
8.62
|
|
|
$
|
(1.48
|
)
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) per Common Share Diluted
|
|
$
|
8.52
|
|
|
$
|
(1.48
|
)
|
|
|
|
|
|
|
|
|
|
The historical financial information was adjusted to give effect
to the pro forma events that were directly attributable to the
acquisitions and merger and factually supportable. The unaudited
pro forma consolidated results are not necessarily indicative of
what the Companys consolidated results of operations
actually would have been had the acquisitions and merger been
completed on January 1, 2009. In addition, the unaudited
pro forma consolidated results do not purport to project the
future results of operations of the combined company. The
unaudited pro forma consolidated results reflect the following
pro forma adjustments:
|
|
|
|
|
Adjustment to recognize incremental depreciation, depletion and
amortization expense, using the
units-of-production
method, resulting from the purchase of the properties;
|
F-18
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
Adjustment to recognize adjusted general and administrative
expense as a result of the purchase of the properties;
|
|
|
|
Adjustment to recognize issuance of $1.5 billion principal
amount of senior unsecured 5.1-percent notes maturing
September 1, 2040, associated deferred financing cost
amortization and interest expense, net of amounts capitalized;
|
|
|
|
Adjustment to recognize asset retirement obligation accretion on
properties acquired;
|
|
|
|
Adjustment to recognize a pro forma income tax provision;
|
|
|
|
Adjustment to recognize the issuance of 26.45 million
shares of Apache common stock to partially fund the BP
acquisitions and 17.3 million shares to partially fund the
Mariner merger;
|
|
|
|
Adjustment to recognize the issuance of 25.3 million
depositary shares each representing a 1/20th interest in a
share of Apaches 6.00-percent Mandatory Convertible
Preferred Stock, Series D, issued to fund a portion of the
BP acquisitions;
|
|
|
|
Adjustment to recognize additional dividends associated with the
issuance of 6.00-percent Mandatory Convertible Preferred
Stock; and
|
|
|
|
Elimination of transaction costs incurred in 2010 that are
directly related to the transactions and do not have a
continuing impact on the combined companys operating
results.
|
Merger,
Acquisitions & Transition Expenses
In 2010, Apache recorded $183 million of expenses in
connection with the acquisition of properties from BP and the
Mariner merger: $114 million of separation and other
payroll costs; $42 million of investment banking fees; and
$27 million of other expenses related to the transactions.
|
|
3.
|
DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES
|
Objectives
and Strategies
The Company is exposed to fluctuations in crude oil and natural
gas prices on the majority of its worldwide production.
Management believes it is prudent to manage the variability in
cash flows by entering into hedges on a portion of its crude oil
and natural gas production. The Company utilizes various types
of derivative financial instruments, including swaps and
options, to manage fluctuations in cash flows resulting from
changes in commodity prices. Derivative instruments entered into
are typically designated as cash flow hedges.
Counterparty
Risk
The use of derivative instruments exposes the Company to
counterparty credit risk, or the risk that a counterparty will
be unable to meet its commitments. To reduce the concentration
of exposure to any individual counterparty, Apache utilizes a
diversified group of investment-grade rated counterparties,
primarily financial institutions, for its derivative
transactions. As of December 31, 2010, Apache had
derivative positions with 20 counterparties. The Company
monitors counterparty creditworthiness on an ongoing basis;
however, it cannot predict sudden changes in
counterparties creditworthiness. In addition, even if such
changes are not sudden, the Company may be limited in its
ability to mitigate an increase in counterparty credit risk.
Should one of these counterparties not perform, Apache may not
realize the benefit of some of its derivative instruments
resulting from lower commodity prices.
The Company executes commodity derivative transactions under
master agreements that have netting provisions that provide for
offsetting payables against receivables. In general, if a party
to a derivative transaction incurs a material deterioration in
its credit ratings, as defined in the applicable agreement, the
other party has the right to demand the posting of collateral,
demand a transfer or terminate the arrangement.
F-19
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Commodity
Derivative Instruments
As of December 31, 2010, Apache had the following open
crude oil derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-Price Swaps
|
|
|
Collars
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
Average
|
|
Production Period
|
|
Mbbls
|
|
|
Fixed Price(1)
|
|
|
Mbbls
|
|
|
Floor Price(1)
|
|
|
Ceiling Price(1)
|
|
|
2011
|
|
|
5,628
|
|
|
$
|
73.36
|
|
|
|
30,110
|
|
|
$
|
69.13
|
|
|
$
|
96.59
|
|
2012
|
|
|
3,786
|
|
|
|
72.26
|
|
|
|
9,142
|
|
|
|
69.30
|
|
|
|
98.11
|
|
2013
|
|
|
1,860
|
|
|
|
74.38
|
|
|
|
2,416
|
|
|
|
78.02
|
|
|
|
103.06
|
|
2014
|
|
|
76
|
|
|
|
74.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Crude oil prices represent a weighted average of several
contracts entered into on a per barrel basis. Crude oil
contracts are primarily settled against NYMEX WTI Cushing Index.
A portion of 2011 contracts are settled against Dated Brent. |
In the fourth quarter of 2010 Apache North Sea Ltd entered into
a physical sales contract to deliver 20 thousand barrels of oil
per day in 2011, settled against Dated Brent with a floor price
of $70 and an average ceiling price of $98.56. These sales are
in the normal course of business and will be recognized in oil
and gas revenues on an accrual basis.
As of December 31, 2010, Apache had the following open
natural gas derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
Collars
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Weighted
|
|
Weighted
|
|
|
MMBtu
|
|
GJ
|
|
Fixed
|
|
MMBtu
|
|
GJ
|
|
Average
|
|
Average
|
Production Period
|
|
(in 000s)
|
|
(in 000s)
|
|
Price(1)
|
|
(in 000s)
|
|
(in 000s)
|
|
Floor Price(1)
|
|
Ceiling Price(1)
|
|
2011
|
|
|
75,927
|
|
|
|
|
|
|
$
|
6.00
|
|
|
|
9,125
|
|
|
|
|
|
|
$
|
5.00
|
|
|
$
|
8.85
|
|
2011
|
|
|
|
|
|
|
51,100
|
|
|
C$
|
6.26
|
|
|
|
|
|
|
|
3,650
|
|
|
C$
|
6.50
|
|
|
C$
|
7.10
|
|
2012
|
|
|
41,554
|
|
|
|
|
|
|
$
|
6.30
|
|
|
|
21,960
|
|
|
|
|
|
|
$
|
5.54
|
|
|
$
|
7.30
|
|
2012
|
|
|
|
|
|
|
43,920
|
|
|
C$
|
6.61
|
|
|
|
|
|
|
|
7,320
|
|
|
C$
|
6.50
|
|
|
C$
|
7.27
|
|
2013
|
|
|
7,665
|
|
|
|
|
|
|
$
|
6.83
|
|
|
|
6,825
|
|
|
|
|
|
|
$
|
5.35
|
|
|
$
|
6.67
|
|
2014
|
|
|
755
|
|
|
|
|
|
|
$
|
7.23
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
(1) |
|
U.S. natural gas prices represent a weighted average of several
contracts entered into on a per million British thermal units
(MMBtu) basis and are settled primarily against NYMEX Henry Hub
and various Inside FERC indices. The Canadian gas contracts are
entered into on a per gigajoule (GJ) basis and are settled
against AECO Index. The Canadian natural gas prices represent a
weighted average of AECO Index prices and are shown in Canadian
dollars. |
Fair
Values of Derivative Instruments Recorded in the Consolidated
Balance Sheet
The Company accounts for derivative instruments and hedging
activity in accordance with ASC Topic 815, Derivatives and
Hedging, and all derivative instruments are reflected as
either assets or liabilities at fair value in the consolidated
balance sheet. These fair values are recorded by netting asset
and liability positions where
F-20
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
counterparty master netting arrangements contain provisions for
net settlement.
The
fair market value of the Companys derivative assets and
liabilities and their locations on the consolidated balance
sheet are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In millions)
|
|
|
Current Assets: Prepaid assets and other
|
|
$
|
167
|
|
|
$
|
13
|
|
Other Assets: Deferred charges and other
|
|
|
139
|
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
306
|
|
|
$
|
64
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities: Derivative instruments
|
|
$
|
194
|
|
|
$
|
128
|
|
Noncurrent Liabilities: Other
|
|
|
124
|
|
|
|
202
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities
|
|
$
|
318
|
|
|
$
|
330
|
|
|
|
|
|
|
|
|
|
|
The methods and assumptions used to estimate the fair values of
the Companys commodity derivative instruments and gross
amounts of commodity derivative assets and liabilities are more
fully discussed in Note 9 Fair Value
Measurements.
Commodity
Derivative Activity Recorded in Statement of Consolidated
Operations
The following table summarizes the effect of derivative
instruments on the Companys statement of consolidated
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
|
|
|
|
Gain (Loss) on Derivatives
|
|
December 31,
|
|
|
|
Recognized in Operations
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
(In millions)
|
|
|
Gain (loss) reclassified from accumulated other comprehensive
income (loss) into operations (effective portion)
|
|
Oil and Gas Production Revenues
|
|
$
|
165
|
|
|
$
|
181
|
|
|
$
|
(436
|
)
|
Gain (loss) on derivatives recognized in operations (ineffective
portion and basis swaps)
|
|
Revenues and Other: Other
|
|
$
|
(2
|
)
|
|
$
|
(4
|
)
|
|
$
|
4
|
|
Commodity
Derivative Activity in Accumulated Other Comprehensive Income
(Loss)
As of December 31, 2010, the Companys derivative
instruments were designated as cash flow hedges in accordance
with ASC Topic 815.
A
reconciliation of the components of accumulated other
comprehensive income (loss) in the statement of consolidated
shareholders equity related to Apaches cash flow
hedges is presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
Before tax
|
|
|
After tax
|
|
|
Before tax
|
|
|
After tax
|
|
|
Before tax
|
|
|
After tax
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) on derivatives at beginning of year
|
|
$
|
(267
|
)
|
|
$
|
(170
|
)
|
|
$
|
212
|
|
|
$
|
138
|
|
|
$
|
(639
|
)
|
|
$
|
(412
|
)
|
Realized (gain) loss reclassified into earnings
|
|
|
(165
|
)
|
|
|
(106
|
)
|
|
|
(181
|
)
|
|
|
(123
|
)
|
|
|
436
|
|
|
|
282
|
|
Net change in derivative fair value
|
|
|
376
|
|
|
|
256
|
|
|
|
(297
|
)
|
|
|
(184
|
)
|
|
|
415
|
|
|
|
268
|
|
Ineffectiveness reclassified into earnings
|
|
|
2
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) on derivatives at end of year
|
|
$
|
(54
|
)
|
|
$
|
(19
|
)
|
|
$
|
(267
|
)
|
|
$
|
(170
|
)
|
|
$
|
212
|
|
|
$
|
138
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains and losses on existing hedges will be realized in future
earnings through mid-2014, in the same period as the related
sales of natural gas and crude oil production applicable to
specific hedges. Included in accumulated other comprehensive
loss as of December 31, 2010 is a net loss of approximately
$45 million ($24 million after tax)
F-21
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
that applies to the next 12 months; however, estimated and
actual amounts are likely to vary materially as a result of
changes in market conditions.
|
|
4.
|
ASSET
RETIREMENT OBLIGATION
|
The following table describes changes to the Companys ARO
liability for the years ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In millions)
|
|
|
Asset retirement obligation at beginning of year
|
|
$
|
1,784
|
|
|
$
|
1,895
|
|
Liabilities incurred
|
|
|
270
|
|
|
|
213
|
|
Liabilities acquired
|
|
|
847
|
|
|
|
5
|
|
Liabilities settled
|
|
|
(329
|
)
|
|
|
(508
|
)
|
Accretion expense
|
|
|
111
|
|
|
|
105
|
|
Revisions in estimated liabilities
|
|
|
189
|
|
|
|
74
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation at end of year
|
|
|
2,872
|
|
|
|
1,784
|
|
Less current portion
|
|
|
(407
|
)
|
|
|
(147
|
)
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation, long-term
|
|
$
|
2,465
|
|
|
$
|
1,637
|
|
|
|
|
|
|
|
|
|
|
The ARO liability reflects the estimated present value of the
amount of dismantlement, removal, site reclamation and similar
activities associated with Apaches oil and gas properties.
The Company utilizes current retirement costs to estimate the
expected cash outflows for retirement obligations. The Company
estimates the ultimate productive life of the properties, a
risk-adjusted discount rate and an inflation factor in order to
determine the current present value of this obligation. To the
extent future revisions to these assumptions impact the present
value of the existing ARO liability, a corresponding adjustment
is made to the oil and gas property balance.
During 2010, the Company recorded additional abandonment
liabilities of $847 million related to the properties
acquired in the BP, Devon and Mariner transactions. Apache also
recorded additional abandonment liabilities of $270 million
associated with its drilling and development program during the
year.
Liabilities settled in 2010 relate to individual properties,
platforms and facilities plugged and abandoned during the
period. The Company has an active abandonment program with a
majority of the activity in the Gulf of Mexico and Canada. In
September 2010 the Bureau of Ocean Management, Regulation and
Enforcement (BOEMRE, formerly known as the Minerals Management
Service), a division of the U.S. Department of the
Interior, issued Notice to Lessees (NTL)
No. 2010-G05,
which includes guidelines for decommissioning idle
infrastructure on active leases in the Gulf of Mexico within a
specified period of time. The Company has reviewed its Gulf of
Mexico abandonment program in light of these new regulations and
adjusted the timing of its abandonment program accordingly.
F-22
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In millions)
|
|
|
U.S.:
|
|
|
|
|
|
|
|
|
Money market lines of credit
|
|
$
|
16
|
|
|
$
|
|
|
Unsecured committed bank credit facilities
|
|
|
|
|
|
|
|
|
Commercial paper
|
|
|
913
|
|
|
|
|
|
6.25% notes due 2012
|
|
|
400
|
|
|
|
400
|
|
5.25% notes due 2013
|
|
|
500
|
|
|
|
500
|
|
6.0% notes due 2013
|
|
|
400
|
|
|
|
400
|
|
5.625% notes due 2017
|
|
|
500
|
|
|
|
500
|
|
6.9% notes due 2018
|
|
|
400
|
|
|
|
400
|
|
7.0% notes due 2018
|
|
|
150
|
|
|
|
150
|
|
7.625% notes due 2019
|
|
|
150
|
|
|
|
150
|
|
3.625% notes due 2021
|
|
|
500
|
|
|
|
|
|
7.7% notes due 2026
|
|
|
100
|
|
|
|
100
|
|
7.95% notes due 2026
|
|
|
180
|
|
|
|
180
|
|
6.0% notes due 2037
|
|
|
1,000
|
|
|
|
1,000
|
|
5.1% notes due 2040
|
|
|
1,500
|
|
|
|
|
|
5.25% notes due 2042
|
|
|
500
|
|
|
|
|
|
7.375% debentures due 2047
|
|
|
150
|
|
|
|
150
|
|
7.625% debentures due 2096
|
|
|
150
|
|
|
|
150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,509
|
|
|
|
4,080
|
|
|
|
|
|
|
|
|
|
|
Subsidiary and other obligations:
|
|
|
|
|
|
|
|
|
Argentina overdraft lines of credit
|
|
|
30
|
|
|
|
7
|
|
Apache PVG secured facility
|
|
|
|
|
|
|
350
|
|
Notes due in 2016 and 2017
|
|
|
1
|
|
|
|
1
|
|
Apache Finance Canada 4.375% notes due 2015
|
|
|
350
|
|
|
|
350
|
|
Apache Finance Canada 7.75% notes due 2029
|
|
|
300
|
|
|
|
300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
681
|
|
|
|
1,008
|
|
|
|
|
|
|
|
|
|
|
Debt at face value
|
|
|
8,190
|
|
|
|
5,088
|
|
Unamortized discount
|
|
|
(49
|
)
|
|
|
(21
|
)
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
8,141
|
|
|
|
5,067
|
|
|
|
|
|
|
|
|
|
|
Current maturities
|
|
|
(46
|
)
|
|
|
(117
|
)
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
8,095
|
|
|
$
|
4,950
|
|
|
|
|
|
|
|
|
|
|
F-23
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Debt maturities as of December 31, 2010, excluding
discounts, are as follows:
|
|
|
|
|
|
|
(In millions)
|
|
|
2011
|
|
$
|
46
|
|
2012
|
|
|
400
|
|
2013
|
|
|
1,813
|
|
2014
|
|
|
|
|
2015
|
|
|
350
|
|
Thereafter
|
|
|
5,581
|
|
|
|
|
|
|
Total Debt, excluding discounts
|
|
$
|
8,190
|
|
|
|
|
|
|
Overview
All of the Companys debt is senior unsecured debt and has
equal priority with respect to the payment of both principal and
interest.
The indentures for the notes described above place certain
restrictions on the Company, including limits on Apaches
ability to incur debt secured by certain liens and its ability
to enter into certain sale and leaseback transactions. Upon
certain changes in control, all of these debt instruments would
be subject to mandatory repurchase, at the option of the
holders. None of the indentures for the notes contain prepayment
obligations in the event of a decline in credit ratings.
Money
Market and Overdraft Lines of Credit
The Company has certain uncommitted money market and overdraft
lines of credit that are used from time to time for working
capital purposes. As of December 31, 2010 and 2009,
$46 million and $7 million, respectively, was drawn on
facilities in the U.S. and Argentina.
Unsecured
Committed Bank Credit Facilities
As of December 31, 2010, the Company had unsecured
committed revolving syndicated bank credit facilities totaling
$3.3 billion, of which $1.0 billion matures in August
2011 and $2.3 billion matures in May 2013. The facilities
consist of a $1.0 billion
364-day
facility, a $1.5 billion facility and a $450 million
facility in the U.S., a $200 million facility in Australia
and a $150 million facility in Canada. As of
December 31, 2010, available borrowing capacity under the
Companys credit facilities was $2.4 billion. The
U.S. credit facilities are used to support Apaches
commercial paper program.
The financial covenants of the credit facilities require the
Company to maintain a
debt-to-capitalization
ratio of not greater than 60 percent at the end of any
fiscal quarter. The Companys
debt-to-capitalization
ratio at December 31, 2010 was 25 percent.
The negative covenants include restrictions on the
Companys ability to create liens and security interests on
its assets, with exceptions for liens typically arising in the
oil and gas industry, purchase money liens and liens arising as
a matter of law, such as tax and mechanics liens. The
Company may incur liens on assets located in the U.S. and
Canada of up to five percent of the Companys consolidated
assets, or approximately $2.2 billion as of
December 31, 2010. There are no restrictions on incurring
liens in countries other than the U.S. and Canada. There
are also restrictions on Apaches ability to merge with
another entity, unless the Company is the surviving entity, and
a restriction on its ability to guarantee debt of entities not
within its consolidated group.
There are no clauses in the facilities that permit the lenders
to accelerate payments or refuse to lend based on unspecified
material adverse changes. The credit facility agreements do not
have drawdown restrictions or prepayment obligations in the
event of a decline in credit ratings. However, the agreements
allow the lenders
F-24
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
to accelerate payments and terminate lending commitments if
Apache Corporation, or any of its U.S. or Canadian
subsidiaries, defaults on any direct payment obligation in
excess of $100 million or has any unpaid, non-appealable
judgment against it in excess of $100 million.
The Company was in compliance with the terms of the credit
facilities as of December 31, 2010.
At the Companys option, the interest rate for the
facilities, excluding the
364-day
facility discussed below, is based on a base rate, as defined,
or the London Inter-bank Offered Rate (LIBOR) plus a margin
determined by the Companys senior long-term debt rating.
The $1.5 billion and the $450 million credit
facilities also allow the Company to borrow under competitive
auctions.
At December 31, 2010, the margin over LIBOR for committed
loans was .19 percent on the $1.5 billion facility and
.23 percent on the $450 million facility in the U.S.,
the $200 million facility in Australia and the
$150 million facility in Canada. If the total amount of the
loans borrowed under the $1.5 billion facility equals or
exceeds 50 percent of the total facility commitments, then
an additional .05 percent will be added to the margins over
LIBOR. If the total amount of the loans borrowed under all of
the other three facilities equals or exceeds 50 percent of
the total facility commitments, then an additional
.10 percent will be added to the margins over LIBOR. The
Company also pays quarterly facility fees of .06 percent on
the total amount of the $1.5 billion facility and
.07 percent on the total amount of the other three
facilities. The facility fees vary based upon the Companys
senior long-term debt rating.
On August 13, 2010, Apache entered into a $1.0 billion
364-day
syndicated revolving credit facility. The credit facility is
subject to covenants, events of default and representations and
warranties that are substantially similar to those in
Apaches existing revolving credit facilities. It may be
used for acquisitions and for general corporate purposes or to
support the Companys commercial paper program.
The facility will terminate and all amounts outstanding will be
due on August 12, 2011, unless Apache requests a
364-day
extension, which is subject to lender approval, as defined, or
Apache elects a one-year term out option. Loans under the
facility will bear interest at a base rate, as defined, or at
LIBOR plus a margin, which varies based upon prices reported in
the credit default swap market with respect to Apaches
one-year indebtedness and the rating for Apaches senior,
unsecured long-term debt. Based upon prices for Apaches
one-year credit default swaps and its current senior unsecured
long-term debt rating, the margin at December 31, 2010,
would be .75 percent. Apache must also pay a commitment fee
on the undrawn portion of the facility which is based on its
senior, unsecured long-term debt rating. The commitment fee is
currently .125 percent.
Commercial
Paper Program
In August 2010 the Company increased its commercial paper
program from $1.95 billion to $2.95 billion. The
commercial paper program generally enables Apache to borrow
funds for up to 270 days at competitive interest rates.
Apaches 2010 weighted-average interest rate for commercial
paper was .37 percent. If the Company is unable to issue
commercial paper following a significant credit downgrade or
dislocation in the market, the Companys U.S. credit
facilities are available as a 100-percent backstop. The
commercial paper program is fully supported by available
borrowing capacity under U.S. committed credit facilities,
which expire in 2011 and 2013. As of December 31, 2010, the
Company had $913 million in commercial paper outstanding.
There was no outstanding commercial paper at December 31,
2009.
Debt
Issuances
On August 20, 2010, the Company issued $1.5 billion
principal amount of senior unsecured 5.1-percent notes maturing
September 1, 2040. The notes are redeemable, as a whole or
in part, at Apaches option, subject to a make-whole
premium. The proceeds were used to repay borrowings under the
Companys bridge facility and commercial paper program.
F-25
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On December 3, 2010, the Company issued $500 million
principal amount of senior unsecured 3.625-percent notes
maturing February 1, 2021, and $500 million principal
amount of senior unsecured 5.25-percent notes maturing
February 1, 2042. The notes are redeemable, as a whole or
in part, at Apaches option, subject to a make-whole
premium. The proceeds were used to redeem the outstanding public
debt assumed upon completion of Apaches acquisition of
Mariner Energy Inc. on November 10, 2010.
U.S. Debt
The U.S. 6.25-percent, 5.625-percent, 6.9-percent,
3.625-percent, 5.1-percent and both issues of 5.25-percent and
6.0-percent notes are redeemable, as a whole or in part, at
Apaches option, subject to a make-whole premium. The
remaining U.S. notes and debentures are not redeemable.
Under certain conditions, the Company has the right to advance
maturity on the U.S. 7.375-percent debentures due 2047 and
7.625-percent debentures due 2096.
Subsidiary
Notes
Apache Finance Canada Apache Finance
Canada Corporation (Apache Finance Canada) has approximately
$300 million of publicly-traded notes due in 2029 and an
additional $350 million of publicly-traded notes due in
2015 that are fully and unconditionally guaranteed by Apache.
For further discussion of subsidiary debt, please see
Note 14 Supplemental Guarantor Information.
Apache Deepwater Apache Deepwater
assumed publicly traded debt upon consummation of its merger
with Mariner. Mariners publicly traded debt included
$300 million of 7.5-percent senior notes due 2013,
$300 million of 11.75-percent senior notes due 2016, and
$300 million of 8-percent senior notes due 2017. On
December 13, 2010, Apache Deepwater redeemed the
7.5-percent notes, the 8-percent notes, and 35 percent of
the 11.75-percent notes pursuant to the provisions of each
notes indenture. On December 14, 2010, Apache
Deepwater redeemed the remaining 65 percent of the
11.75-percent notes.
Subsidiary
Project Financing
In June 2010 one of the Companys Australian subsidiaries
repaid $50 million under its amortizing secured revolving
syndicated credit facility for its Van Gogh and Pyrenees oil
developments offshore Western Australia. The remaining balance
of $300 million was repaid in December 2010. Upon repayment
of the remaining balance of the facility, all commitments under
the facility were terminated and assets secured by the facility
were released.
Financing
Costs, Net
Financing costs incurred during the periods are composed of the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Interest expense
|
|
$
|
345
|
|
|
$
|
309
|
|
|
$
|
280
|
|
Amortization of deferred loan costs
|
|
|
17
|
|
|
|
6
|
|
|
|
4
|
|
Capitalized interest
|
|
|
(120
|
)
|
|
|
(61
|
)
|
|
|
(94
|
)
|
Interest income
|
|
|
(13
|
)
|
|
|
(12
|
)
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financing costs, net
|
|
$
|
229
|
|
|
$
|
242
|
|
|
$
|
166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company has $49 million of debt discounts as of
December 31, 2010, which will be charged to interest
expense over the life of the related debt issuances. In
connection with the 2010 debt issuances discussed above, Apache
recorded $30 million in additional debt discounts. Discount
amortization of $2 million, $1 million and
$1 million were recorded as interest expense in 2010, 2009
and 2008, respectively.
F-26
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As of December 31, 2010 and 2009, the Company had
approximately $53 million and $40 million,
respectively, of unamortized deferred loan costs associated with
its various debt obligations. These costs are included in
deferred charges and other in the accompanying consolidated
balance sheet and are being charged to financing costs and
expensed over the life of the related debt issuances.
Income before income taxes is composed of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
United States
|
|
$
|
1,328
|
|
|
$
|
(567
|
)
|
|
$
|
(350
|
)
|
Foreign
|
|
|
3,878
|
|
|
|
893
|
|
|
|
1,282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,206
|
|
|
$
|
326
|
|
|
$
|
932
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total provision for income taxes consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Current taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
25
|
|
|
$
|
(130
|
)
|
|
$
|
128
|
|
State
|
|
|
4
|
|
|
|
(2
|
)
|
|
|
1
|
|
Foreign
|
|
|
1,193
|
|
|
|
974
|
|
|
|
1,327
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,222
|
|
|
|
842
|
|
|
|
1,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
431
|
|
|
|
(81
|
)
|
|
|
(414
|
)
|
State
|
|
|
7
|
|
|
|
(24
|
)
|
|
|
3
|
|
Foreign
|
|
|
514
|
|
|
|
(126
|
)
|
|
|
(825
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
952
|
|
|
|
(231
|
)
|
|
|
(1,236
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,174
|
|
|
$
|
611
|
|
|
$
|
220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A reconciliation of the tax on the Companys income before
income taxes and total tax expense is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Income tax expense at U.S. statutory rate
|
|
$
|
1,822
|
|
|
$
|
114
|
|
|
$
|
326
|
|
State income tax, less federal benefit
|
|
|
6
|
|
|
|
(17
|
)
|
|
|
3
|
|
Taxes related to foreign operations
|
|
|
245
|
|
|
|
310
|
|
|
|
430
|
|
Tax credits
|
|
|
(8
|
)
|
|
|
(39
|
)
|
|
|
|
|
Non-deductible merger costs
|
|
|
6
|
|
|
|
|
|
|
|
|
|
Current and deferred taxes related to currency fluctuations
|
|
|
111
|
|
|
|
195
|
|
|
|
(400
|
)
|
Domestic manufacturing deduction
|
|
|
|
|
|
|
|
|
|
|
(7
|
)
|
Net change in tax contingencies
|
|
|
(2
|
)
|
|
|
36
|
|
|
|
(140
|
)
|
Increase in valuation allowance
|
|
|
12
|
|
|
|
20
|
|
|
|
3
|
|
All other, net
|
|
|
(18
|
)
|
|
|
(8
|
)
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,174
|
|
|
$
|
611
|
|
|
$
|
220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-27
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The net deferred tax liability consists of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In millions)
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Deferred income
|
|
$
|
(6
|
)
|
|
$
|
(20
|
)
|
Federal and state net operating loss carryforwards
|
|
|
(277
|
)
|
|
|
(35
|
)
|
Foreign net operating loss carryforwards
|
|
|
(55
|
)
|
|
|
(225
|
)
|
Tax credits
|
|
|
(42
|
)
|
|
|
(48
|
)
|
Accrued expenses and liabilities
|
|
|
(76
|
)
|
|
|
(105
|
)
|
Other
|
|
|
(25
|
)
|
|
|
(60
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
(481
|
)
|
|
|
(493
|
)
|
Valuation allowance
|
|
|
53
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
(428
|
)
|
|
|
(458
|
)
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
4,569
|
|
|
|
3,068
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
4,569
|
|
|
|
3,068
|
|
|
|
|
|
|
|
|
|
|
Net deferred income tax liability
|
|
$
|
4,141
|
|
|
$
|
2,610
|
|
|
|
|
|
|
|
|
|
|
The Company has not recorded U.S. deferred income taxes on
the undistributed earnings of its foreign subsidiaries as
management intends to permanently reinvest such earnings. As of
December 31, 2010, the undistributed earnings of the
foreign subsidiaries amounted to approximately
$19.2 billion. Upon distribution of these earnings in the
form of dividends or otherwise, the Company may be subject to
U.S. income taxes and foreign withholding taxes. It is not
practical, however, to estimate the amount of taxes that may be
payable on the eventual remittance of these earnings after
consideration of available foreign tax credits. Presently,
limited foreign tax credits are available to reduce the
U.S. taxes on such amounts if repatriated.
On December 31, 2010, the Company had U.S. net
operating losses of $656 million, state net operating loss
carryforwards of $862 million and foreign net operating
loss carryforwards of $59 million in Canada and
$20 million in Argentina. The Company also had
$234 million of capital loss carryforwards in Canada. The
state net operating losses will expire over the next
20 years if they are not otherwise utilized. The foreign
net operating loss in Canada will begin to expire in 2014, and
the Argentina net operating loss will begin to expire in 2011.
The capital loss in Canada has an indefinite carryover period.
The Companys federal net operating loss carryforward of
$636 million is related to the merger with Mariner and is
subject to annual limitations under Section 382 of the
Internal Revenue Code.
The tax benefits of carryforwards are recorded as assets 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 to not meet the more likely than not
standard, a valuation allowance is provided to reduce the tax
benefits from such assets. As the Company does not believe the
utilization of certain Canadian capital losses and certain
Argentina and U.S. state net operating losses to be
more likely than not, a valuation allowance was
provided to reduce the tax benefit from these deferred tax
assets.
F-28
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Apache accounts for income taxes in accordance with ASC Topic
740, Income Taxes, which prescribes a minimum
recognition threshold a tax position must meet before being
recognized in the financial statements.
A
reconciliation of the beginning and ending amount of
unrecognized tax benefits is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Balance at beginning of year
|
|
$
|
123
|
|
|
$
|
213
|
|
|
$
|
508
|
|
Additions based on tax positions related to the current year
|
|
|
(1
|
)
|
|
|
23
|
|
|
|
|
|
Additions for tax positions of prior years
|
|
|
|
|
|
|
77
|
|
|
|
48
|
|
Reductions for tax positions of prior years
|
|
|
(12
|
)
|
|
|
(92
|
)
|
|
|
(337
|
)
|
Settlements
|
|
|
|
|
|
|
(98
|
)
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year
|
|
$
|
110
|
|
|
$
|
123
|
|
|
$
|
213
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in the balances at December 31, 2010 and 2009 are
$14 million of tax positions for which the ultimate
deductibility is highly certain, but for which there is
uncertainty about the timing of such deductibility. Because of
the impact of deferred tax accounting, other than penalties and
interest, the disallowance of the shorter deductibility period
would not affect the annual effective income tax rate but would
accelerate the payment of cash to the taxing authority to an
earlier period.
The Company records interest and penalties related to
unrecognized tax benefits as a component of income tax expense.
Each quarter the Company assesses the amounts provided for and,
as a result, may increase (expense) or reduce (benefit) the
amount of interest and penalties. During the years ended
December 31, 2010 and 2009, the Company recorded tax
expense of $12 million and a benefit of $17 million,
respectively. In 2008, the Company recorded a tax benefit of
$87 million for interest and penalties. As of
December 31, 2010 and 2009, the Company had approximately
$36 million and $24 million, respectively, accrued for
payment of interest and penalties.
The Company is in Administrative Appeals with the
U.S. Internal Revenue Service (IRS) regarding the tax years
2004 through 2007. The Company is also under IRS audit for 2008
and under audit in various states and in most of the
Companys foreign jurisdictions as part of its normal
course of business. Resolution of any of the above, which may
occur in 2011, could result in a significant change to the
Companys tax reserves. However, the resolution of unagreed
tax issues in the Companys open tax years cannot be
predicted with absolute certainty, and differences between what
has been recorded and the eventual outcomes may occur. Due to
this uncertainty and the uncertain timing of the final
resolution of the Appeals process, an accurate estimate of the
range of outcomes occurring during the next 12 months
cannot be made at this time. Nevertheless, the Company believes
that it has adequately provided for income taxes and any related
interest and penalties for all open tax years.
Apache and its subsidiaries are subject to U.S. federal
income tax as well as income tax in various states and foreign
jurisdictions.
The
Companys uncertain tax positions are related to tax years
that may be subject to examination by the relevant taxing
authority. Apaches earliest open tax years in its key
jurisdictions are as follows:
|
|
|
|
|
Jurisdiction
|
|
|
|
|
United States
|
|
|
2004
|
|
Canada
|
|
|
2006
|
|
Egypt
|
|
|
1998
|
|
Australia
|
|
|
2001
|
|
United Kingdom
|
|
|
2009
|
|
Argentina
|
|
|
2003
|
|
F-29
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Common
Stock Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Balance, beginning of year
|
|
|
336,436,972
|
|
|
|
334,710,064
|
|
|
|
332,927,143
|
|
Shares issued for stock-based compensation plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury shares issued
|
|
|
363,263
|
|
|
|
404,232
|
|
|
|
350,895
|
|
Common shares issued
|
|
|
1,864,498
|
|
|
|
1,322,676
|
|
|
|
1,432,026
|
|
Equity offering (BP acquisitions)
|
|
|
26,450,000
|
|
|
|
|
|
|
|
|
|
Mariner consideration
|
|
|
17,277,009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
|
382,391,742
|
|
|
|
336,436,972
|
|
|
|
334,710,064
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss) Per Common Share
A reconciliation of the components of basic and diluted net
income (loss) per common share for the years ended
December 31, 2010, 2009 and 2008 is presented in the table
below. The loss for 2009 reflects an after-tax write-down for
full-cost accounting of $1.98 billion. Income for 2008
reflects an after-tax write-down for full-cost accounting of
$3.6 billion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
Income
|
|
|
Shares
|
|
|
Per Share
|
|
|
Loss
|
|
|
Shares
|
|
|
Per Share
|
|
|
Income
|
|
|
Shares
|
|
|
Per Share
|
|
|
|
(In millions, except per share amounts)
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) attributable to common stock
|
|
$
|
3,000
|
|
|
|
352
|
|
|
$
|
8.53
|
|
|
$
|
(292
|
)
|
|
|
336
|
|
|
$
|
(.87
|
)
|
|
$
|
706
|
|
|
|
334
|
|
|
$
|
2.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mandatory Convertible Preferred Stock
|
|
$
|
32
|
|
|
|
5
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Stock options and other
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) attributable to common stock, including assumed
conversions
|
|
$
|
3,032
|
|
|
|
359
|
|
|
$
|
8.46
|
|
|
$
|
(292
|
)
|
|
|
336
|
|
|
$
|
(.87
|
)
|
|
$
|
706
|
|
|
|
337
|
|
|
$
|
2.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The diluted earnings per share calculation excludes options and
restricted shares that were anti-dilutive totaling
2.3 million, 4.2 million and .7 million for the
years ended December 31, 2010, 2009 and 2008, respectively.
Issuance
of Common Stock
On July 28, 2010, in conjunction with Apaches
acquisition of properties from BP, the Company issued
26.45 million shares of common stock at a public offering
price of $88 per share. Proceeds, after underwriting discounts
and before expenses, from the common stock offering totaled
approximately $2.3 billion.
On November 10, 2010, in connection with the Mariner
merger, Apache issued 17.3 million shares of common stock
in exchange for Mariner common and restricted stock. The total
value of stock consideration, based on the November 10,
2010, closing value on the NYSE of $110.25 per share, was
approximately $1.9 billion.
For further discussion of the BP acquisitions and Mariner
merger, please see Note 2 Acquisitions.
F-30
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Common
Stock Dividend
The Company paid common stock dividends of $.60, $.60 and $.70
per share in 2010, 2009 and 2008, respectively. The higher
common stock dividends for 2008 were attributable to a special
cash dividend of 10 cents per common share paid on
March 18, 2008.
Stock
Compensation Plans
The Company has several stock-based compensation plans, which
include stock options, stock appreciation rights, restricted
stock, and performance-based share appreciation plans. In May
2007, the Companys shareholders approved the 2007 Omnibus
Equity Compensation Plan (the 2007 Plan), which is intended to
provide eligible employees with equity-based incentives. The
2007 Plan provides for the granting of Incentive Stock Options,
Non-Qualified Stock Options, Performance Awards, Restricted
Stock, Restricted Stock Units, Stock Appreciation Rights, or any
combination of the foregoing. All new grants are issued from the
2007 Plan. The previous plans remain in effect solely for the
purpose of governing grants still outstanding that were issued
prior to approval of the 2007 Plan, including the
2005 Share Appreciation Plan, which remains in effect to
issue shares for previously-attained stock appreciation goals.
For 2010, 2009 and 2008, stock-based compensation expensed was
$164 million, $104 million and $52 million
($106 million, $67 million and $34 million after
tax), respectively. Costs related to the plans are capitalized
or expensed based on the nature of each employees
activities.
A
description of the Companys stock-based compensation plans
and related costs follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Stock-based compensation expensed:
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
$
|
98
|
|
|
$
|
67
|
|
|
$
|
34
|
|
Lease operating expenses
|
|
|
66
|
|
|
|
37
|
|
|
|
18
|
|
Stock-based compensation capitalized
|
|
|
71
|
|
|
|
46
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
235
|
|
|
$
|
150
|
|
|
$
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
Options
As of December 31, 2010, officers and employees held
options to purchase shares of the Companys common stock
under one or more of the employee stock option plans adopted in
1998, 2000 and 2005 (collectively, the Stock Option Plans), and
under the 2007 Plan discussed above. New shares of Company stock
will be issued for employee stock option exercises; however,
under the 2000 Stock Option Plan, shares of treasury stock are
used for employee stock option exercises to the extent treasury
stock is held. Under the Stock Option Plans and the 2007 Plan,
the exercise price of each option equals the closing price of
Apaches common stock on the date of grant. Options
generally become exercisable ratably over a four-year period and
expire 10 years after granted. All of these plans allow for
accelerated vesting if there is a change in control, as defined
in each plan. The 2007 Plan and all of the Stock Option Plans,
except for the 2000 Stock Option Plan, were submitted to and
approved by the Companys shareholders.
F-31
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A summary of stock options issued and outstanding under the
Stock Option Plans and the 2007 Plan is presented in the table
and narrative below (shares in thousands):
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
|
Shares
|
|
|
Weighted Average
|
|
|
|
Under Option
|
|
|
Exercise Price
|
|
|
|
(In thousands)
|
|
|
|
|
|
Outstanding, beginning of year
|
|
|
5,920
|
|
|
$
|
72.29
|
|
Granted
|
|
|
1,213
|
|
|
|
99.30
|
|
Mariner options converted to Apache options
|
|
|
145
|
|
|
|
57.42
|
|
Exercised
|
|
|
(1,266
|
)
|
|
|
57.34
|
|
Forfeited or expired
|
|
|
(151
|
)
|
|
|
89.44
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of year(1)
|
|
|
5,861
|
|
|
|
80.30
|
|
|
|
|
|
|
|
|
|
|
Expected to vest(1)
|
|
|
2,119
|
|
|
|
91.84
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of year(1)
|
|
|
3,248
|
|
|
|
70.62
|
|
|
|
|
|
|
|
|
|
|
Available for grant, end of year
|
|
|
1,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value of options granted during the year
|
|
$
|
34.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
As of December 31, 2010, the weighted average remaining
contractual life for options outstanding, expected to vest, and
exercisable is 6.6 years, 8.3 years and
5.2 years, respectively. The aggregate intrinsic value of
options outstanding, expected to vest and exercisable at
year-end was $233 million, $60 million and
$161 million, respectively. The weighted-average grant-date
fair value of options granted during the years 2010, 2009 and
2008 was $34.12, $29.71 and $39.76, respectively. |
The fair value of each stock option award is estimated on the
date of grant using the Black-Scholes option pricing model.
Assumptions used in the valuation are disclosed in the following
table. Expected volatilities are based on historical volatility
of the Companys common stock and other factors. The
expected dividend yield is based on historical yields on the
date of grant. The expected term of stock options granted
represents the period of time that the stock options are
expected to be outstanding and is derived from historical
exercise behavior, current trends and values derived from
lattice-based models. The risk-free rate is based on the
U.S. Treasury yield curve in effect at the time of grant.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Expected volatility
|
|
|
35.02
|
%
|
|
|
38.73
|
%
|
|
|
27.93
|
%
|
Expected dividend yields
|
|
|
.60
|
%
|
|
|
.73
|
%
|
|
|
.53
|
%
|
Expected term (in years)
|
|
|
5.5
|
|
|
|
5.5
|
|
|
|
5.5
|
|
Risk-free rate
|
|
|
2.31
|
%
|
|
|
2.06
|
%
|
|
|
3.04
|
%
|
The intrinsic value of options exercised during 2010, 2009 and
2008 was approximately $62 million, $39 million and
$100 million, respectively. The cash received from exercise
of options during 2010 was approximately $73 million. The
Company realized an additional tax benefit of approximately
$14 million for the amount of intrinsic value in excess of
compensation cost recognized in 2010. As of December 31,
2010, the total compensation cost related to non-vested options
not yet recognized was $62 million, which will be
recognized over the remaining vesting period of the options.
Stock
Appreciation Rights
In 2003 and 2004, respectively, the Company issued a total of
1,809,060 and 1,334,300 of stock appreciation rights (SARs) to
non-executive employees in lieu of stock options. The SARs
vested ratably over four years and are
F-32
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
settled in cash upon exercise throughout their
10-year
life. The weighted-average exercise price was $42.68 and $28.78
for those issued in 2004 and 2003, respectively. The number of
SARs outstanding and exercisable as of December 31, 2010
was 595,786. Since SARs are cash-settled, the Company records
compensation expense based on the fair value of the SARs at the
end of each period. As of year-end, the weighted-average fair
value of SARs outstanding was $84.29 based on the Black-Scholes
valuation methodology using assumptions comparable to those
discussed above. During 2010, 181,697 SARs were exercised. The
aggregate of cash payments made to settle SARs was
$13 million.
Restricted
Stock and Restricted Stock Units
The Company has restricted stock and restricted stock unit
plans, including those awarded pursuant to programs under the
2007 Plan, for eligible employees including officers. The
programs created under the 2007 Plan have been approved by
Apaches Board of Directors. In 2010 the Company awarded
1,143,989 restricted stock units at a weighted-average per-share
market price of $103.88. In 2009 and 2008 the Company awarded
1,119,936 and 787,846 restricted stock units at a
weighted-average per-share market price of $84.30 and $136.05,
respectively. The value of the stock issued was established by
the market price on the date of grant and is being recorded as
compensation expense ratably over the vesting terms. During
2010, 2009 and 2008, $73 million ($47 million after
tax), $37 million ($24 million after tax) and
$20 million ($13 million after tax), respectively, was
charged to expense. In 2010, 2009 and 2008, $28 million,
$12 million and $6 million was capitalized,
respectively. As of December 31, 2010, there was
$160 million of total unrecognized compensation cost
related to 2,209,722 unvested restricted stock units. The
weighted-average remaining life of unvested restricted stock
units is approximately 1.3 years.
The fair value of the awards vesting during 2010, 2009 and 2008
was approximately $69 million, $34 million and
$15 million, respectively.
A summary of restricted stock
activity for the year ended December 31, 2010 is presented
below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
Average Grant-
|
|
Restricted Stock
|
|
Shares
|
|
|
Date Fair Value
|
|
|
|
(In thousands)
|
|
|
|
|
|
Non-vested at January 1, 2010
|
|
|
1,835
|
|
|
$
|
98.95
|
|
Granted
|
|
|
1,144
|
|
|
|
103.88
|
|
Vested
|
|
|
(686
|
)
|
|
|
101.27
|
|
Forfeited
|
|
|
(83
|
)
|
|
|
100.46
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2010
|
|
|
2,210
|
|
|
|
100.72
|
|
|
|
|
|
|
|
|
|
|
Conditional
Restricted Stock Units
To provide long-term incentives for Apache employees to deliver
competitive returns to the Companys stockholders, in
January 2010 the Companys Board of Directors approved the
2010 Performance Program, pursuant to the 2007 Plan. Eligible
employees received initial conditional restricted stock unit
awards totaling 541,465 units. A total of
523,240 units were outstanding at December 31, 2010,
from which a minimum of zero and a maximum of
1,353,663 units could be awarded based upon measurement of
total shareholder return of Apache common stock as compared to a
designated peer group during a three-year performance period.
Should any restricted stock units be awarded at the end of the
three-year performance period, 50 percent of restricted
stock units awarded will immediately vest, and an additional
25 percent will vest on succeeding anniversaries of the end
of the performance period.
The fair value cost of the awards was estimated on the date of
grant and is being recorded as compensation expense ratably over
the vesting terms. During 2010, $7 million ($4 million
after tax) was charged to expense and $3 million was
capitalized. As of December 31, 2010, there was
$65 million of total unrecognized compensation
F-33
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
cost related to 523,240 unvested conditional restricted stock
units. The weighted-average remaining life of the unvested
conditional restricted stock units is approximately
2.8 years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
Average Grant-
|
|
Conditional Restricted Stock Award
|
|
Shares
|
|
|
Date Fair Value(1)
|
|
|
|
(In thousands)
|
|
|
|
|
|
Non-vested at January 1, 2010
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
541
|
|
|
|
141.86
|
|
Forfeited
|
|
|
(18
|
)
|
|
|
141.86
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2010
|
|
|
523
|
|
|
|
141.86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The fair value of each conditional restricted stock unit award
is estimated as of the date of grant using a Monte Carlo
simulation with the following assumptions used for all grants
made under the plan: (i) a three-year continuous risk-free
interest rate; (ii) a constant volatility assumption based
on the historical realized price volatility of the Company and
the designated peer group; and (iii) the historical stock
prices and expected dividends of the common stock of the Company
and its designated peer group. |
In January 2011 the Companys Board of Directors approved
the 2011 Performance Program, pursuant to the 2007 Plan, with
terms similar to the 2010 Performance Program. Eligible
employees received initial conditional restricted stock unit
awards totaling 585,715 units, with the ultimate number of
restricted stock units to be awarded ranging from zero to a
maximum of 1,464,288 units.
Share
Appreciation Plans
The Company has previously utilized share appreciation plans to
provide incentives for substantially all full-time employees and
officers to increase Apaches share price within a stated
measurement period. To achieve the payout, the Companys
stock price must close at or above a stated threshold for 10 out
of any 30 consecutive trading days before the end of the stated
period. Awards under the plans are payable in equal annual
installments as specified by each plan, beginning on a date not
more than 30 days after a threshold is attained for the
required measurement period and on succeeding anniversaries of
the attainment date. Shares issued to employees are reduced by
the required minimum tax withholding. Shares of Apache common
stock contingently issuable under the plans are excluded from
the computation of income per common share until the stated
goals are met as described below.
Since 2005, two share appreciation plans have been approved. A
summary of these plans is as follows:
|
|
|
|
|
On May 7, 2008, the Stock Option Plan Committee of the
Companys Board of Directors, pursuant to the
Companys 2007 Omnibus Equity Compensation Plan, approved
the 2008 Share Appreciation Program with a target to
increase Apaches share price to $216 by the end of 2012
and an interim goal of $162 to be achieved by the end of 2010.
Any awards under the program would be payable in five equal
annual installments. The interim target of $162 was not met by
the end of 2010, and the related awards were cancelled. The
$216 share price target has not been met.
|
|
|
|
On May 5, 2005, the Companys stockholders approved
the 2005 Share Appreciation Plan, with a target to increase
Apaches share price to $108 by the end of 2008 and an
interim goal of $81 to be achieved by the end of 2007. Awards
under the plan are payable in four equal annual installments to
eligible employees remaining with the Company. Apaches
share price exceeded the interim $81 threshold for the
10-day
requirement as of June 14, 2007, and the first and second
installments were awarded in July 2007 and 2008. The third and
fourth installments were awarded in June 2009 and 2010.
Apaches share price exceeded the $108 threshold for the
10-day
requirement as of February 29, 2008. The first three
installments were awarded in March 2008, 2009 and 2010, and the
fourth installment will be awarded in March 2011.
|
F-34
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A summary of the number of shares contingently issuable as of
December 31, 2010, 2009 and 2008 for each plan is presented
in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Subject to
|
|
|
|
Conditional Grants
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
2008 Share Appreciation Program
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of year
|
|
|
2,592
|
|
|
|
2,814
|
|
|
|
|
|
Granted
|
|
|
25
|
|
|
|
93
|
|
|
|
2,929
|
|
Forfeited or cancelled
|
|
|
(1,132
|
)
|
|
|
(315
|
)
|
|
|
(115
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of year(1)
|
|
|
1,485
|
|
|
|
2,592
|
|
|
|
2,814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average fair value of grants outstanding(2)
|
|
$
|
71.16
|
|
|
$
|
79.61
|
|
|
$
|
81.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 Share Appreciation Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of year
|
|
|
1,103
|
|
|
|
2,001
|
|
|
|
2,945
|
|
Issued(3)
|
|
|
(678
|
)
|
|
|
(815
|
)
|
|
|
(805
|
)
|
Forfeited or cancelled
|
|
|
(25
|
)
|
|
|
(83
|
)
|
|
|
(139
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of year
|
|
|
400
|
|
|
|
1,103
|
|
|
|
2,001
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average fair value of grants outstanding(4)
|
|
$
|
21.64
|
|
|
$
|
24.29
|
|
|
$
|
24.98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents shares issuable upon target achievement and vesting
of awards related to the $216 and $162 per share price goals of
1,485,210 and zero shares, respectively, at December 31,
2010; 1,556,160 and 1,035,640 shares, respectively, at
December 31, 2009; and 1,685,430 and 1,128,320 shares,
respectively, at December 31, 2008. |
|
(2) |
|
The fair value of each Share Price Goal conditional grant is
estimated as of the date of grant using a Monte Carlo simulation
with the following weighted-average assumptions used for all
grants made under the plan: (i) risk-free interest rate of
2.98 percent; (ii) expected volatility of
28.31 percent; and (iii) expected dividend yield of
.54 percent. |
|
(3) |
|
The total fair value of these awards vested during 2010, 2009
and 2008 was approximately $18 million, $21 million
and $21 million, respectively. |
|
(4) |
|
The fair value of each Share Price Goal conditional grant is
estimated as of the date of grant using a Monte Carlo simulation
with the following weighted-average assumptions used for all
grants made under the plan: (i) risk-free interest rate of
3.95 percent; (ii) expected volatility of
28.02 percent; and (iii) expected dividend yield of
.57 percent. |
Current accounting practices dictate that the Company recognize,
over the requisite service period, the fair value cost
determined at the grant date based on numerous assumptions,
including an estimate of the likelihood that Apaches stock
price will achieve these thresholds and the expected forfeiture
rate. If a price target is not met before the end of the stated
achievement period, any unamortized expense must be immediately
recognized. Since the $162 interim price target of the 2008
Share Appreciation Program was not met prior to the stated
achievement period, December 31, 2010, Apache recognized
$27 million of unamortized expense and $14 million of
unamortized capital costs. The Company will recognize total
expense and capitalized costs for the 2008 Share Appreciation
Program and the 2005 Share Appreciation Plan over the expected
service life of each program: approximately $195 million
through 2014 for the 2008 Share Appreciation Program and
$79 million through 2011
F-35
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
for the 2005 Share Appreciation Plan.
A
summary of the amounts recognized as expense and capitalized
costs for each plan are detailed in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
2008 Share Appreciation Program
|
|
|
|
|
|
|
|
|
|
|
|
|
Compensation expense
|
|
$
|
49
|
|
|
$
|
23
|
|
|
$
|
15
|
|
Compensation expense, net of tax
|
|
|
31
|
|
|
|
15
|
|
|
|
10
|
|
Capitalized costs
|
|
|
27
|
|
|
|
13
|
|
|
|
8
|
|
2005 Share Appreciation Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
Compensation expense
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
9
|
|
Compensation expense, net of tax
|
|
|
4
|
|
|
|
4
|
|
|
|
6
|
|
Capitalized costs
|
|
|
3
|
|
|
|
3
|
|
|
|
5
|
|
Preferred
Stock
The Company has 5,000,000 shares of no par preferred stock
authorized, of which 25,000 shares have been designated as
Series A Junior Participating Preferred Stock (the
Series A Preferred Stock). The Company redeemed the 100,000
outstanding shares of its 5.68 percent Series B
Cumulative Preferred Stock (the Series B Preferred Stock)
on December 30, 2009.
Series A
Preferred Stock
In December 1995, the Company declared a dividend of one right
(a Right) for each 2.31 shares (adjusted for subsequent
stock dividends and a
two-for-one
stock split) of Apache common stock outstanding on
January 31, 1996. Each full Right entitles the registered
holder to purchase from the Company one ten-thousandth
(1/10,000) of a share of Series A Preferred Stock at a
price of $100 per one ten-thousandth of a share, subject to
adjustment. The Rights are exercisable 10 calendar days
following a public announcement that certain persons or groups
have acquired 20 percent or more of the outstanding shares
of Apache common stock or 10 business days following
commencement of an offer for 30 percent or more of the
outstanding shares of Apaches outstanding common stock
(flip in event); each Right will become exercisable for shares
of Apaches common stock at 50 percent of the
then-market price of the common stock. If a 20-percent
shareholder of Apache acquires Apache, by merger or otherwise,
in a transaction where Apache does not survive or in which
Apaches common stock is changed or exchanged (flip over
event), the Rights become exercisable for shares of the common
stock of the Company acquiring Apache at 50 percent of the
then-market price for Apache common stock. Any Rights that are
or were beneficially owned by a person who has acquired
20 percent or more of the outstanding shares of Apache
common stock and who engages in certain transactions or realizes
the benefits of certain transactions with the Company will
become void. If an offer to acquire all of the Companys
outstanding shares of common stock is determined to be fair by
Apaches board of directors, the transaction will not
trigger a flip in event or a flip-over event. The Company may
also redeem the Rights at $.01 per Right at any time until 10
business days after public announcement of a flip in event.
These rights were originally scheduled to expire on
January 31, 2006. Effective as of that date, the Rights
were reset to one right per share of common stock and the
expiration was extended to January 31, 2016. Unless the
Rights have been previously redeemed, all shares of Apache
common stock issued by the Company after January 31, 1996
will include Rights. Unless and until the Rights become
exercisable, they will be transferred with and only with the
shares of Apache common stock.
F-36
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Series B
Preferred Stock
In August 1998, Apache issued 100,000 shares
($100 million) of Series B Preferred Stock in the form
of one million depositary shares, each representing one-tenth
(1/10) of a share of Series B Preferred Stock, for net
proceeds of $98 million. On December 30, 2009, Apache
redeemed all Series B Preferred Stock at $1,000 per
preferred share plus $9.47 in accrued and unpaid dividends.
Holders of the shares were entitled to receive cumulative cash
dividends at an annual rate of $5.68 per depositary share.
During 2009 and 2008 Apache accrued a total of $6 million
each year in dividends on its Series B Preferred Stock
issued in August 1998. As the final dividend payment was
accelerated with the redemption of the Series B Preferred
Stock, Apache paid $7 million in dividends on this stock
during 2009, compared to $6 million during 2008. These
preferred shares were redeemed on December 30, 2009.
Series D
Preferred Stock
On July 28, 2010, Apache issued 25.3 million
depositary shares, each representing a 1/20th interest in a
share of Apaches 6.00-percent Mandatory Convertible
Preferred Stock, Series D (Preferred Share), or
1.265 million Preferred Shares. The Company received
proceeds of approximately $1.2 billion, after underwriting
discounts and before expenses, from the sale.
Each Preferred Share has an initial liquidation preference of
$1,000 per share (equivalent to $50 liquidation preference per
depositary share). When and if declared by the Board of
Directors, Apache will pay cumulative dividends on each
Preferred Share at a rate of 6.00 percent per annum on the
initial liquidation preference. Dividends will be paid in cash
quarterly on February 1, May 1, August 1 and November
1 of each year, commencing on November 1, 2010, and until
and including May 1, 2013. The final dividend payment on
August 1, 2013, may be paid or delivered, as the case may
be, in cash, shares of Apache common stock, or a combination
thereof, at the election of the Company.
The Preferred Shares may be converted, at the option of the
holder, into 9.164 shares of Apache common stock at any
time prior to July 15, 2013. If not converted prior to that
time, each Preferred Share will automatically convert on
August 1, 2013, into a minimum of 9.164 or a maximum of
11.364 shares of Apache common stock depending on the
volume-weighted average price per share of Apaches common
stock over the ten trading day period ending on, and including,
the third scheduled trading day immediately preceding the
mandatory conversion. Upon conversion, a minimum of
11.6 million Apache common shares and a maximum of
14.4 million common shares will be issued.
Accumulated
Other Comprehensive Income (Loss)
Components of accumulated other comprehensive income (loss)
consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Currency translation adjustment(1)
|
|
$
|
(109
|
)
|
|
$
|
(109
|
)
|
|
$
|
(109
|
)
|
Unrealized gain (loss) on derivatives (Note 3)
|
|
|
(19
|
)
|
|
|
(170
|
)
|
|
|
138
|
|
Unfunded pension and postretirement benefit plan
|
|
|
(13
|
)
|
|
|
(11
|
)
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss)
|
|
$
|
(141
|
)
|
|
$
|
(290
|
)
|
|
$
|
22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Prior to October 1, 2002, the Companys Canadian
subsidiaries functional currency was the Canadian dollar.
Translation adjustments resulting from translating the Canadian
subsidiaries financial statements into U.S. dollar
equivalents were reported separately and accumulated in other
comprehensive income (loss). Currency translation adjustments
held in other comprehensive income (loss) on the balance sheet
will remain there indefinitely unless there is a substantially
complete liquidation of the Companys Canadian operations. |
F-37
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
8.
|
COMMITMENTS
AND CONTINGENCIES
|
Legal
Matters
Apache is party to various legal actions arising in the ordinary
course of business, including litigation and governmental and
regulatory controls. The Company has an accrued liability of
approximately $14 million for all legal contingencies that
are deemed to be probable of occurring and can be reasonably
estimated. Apaches estimates are based on information
known about the matters and its experience in contesting,
litigating and settling similar matters. Although actual amounts
could differ from managements estimate, none of the
actions are believed by management to involve future amounts
that would be material to Apaches financial position or
results of operations after consideration of recorded accruals.
It is managements opinion that the loss for any other
litigation matters and claims that are reasonably possible to
occur will not have a material adverse effect on the
Companys financial position or results of operations.
Argentine
Environmental Claims
In connection with the acquisition from Pioneer in 2006, the
Company acquired a subsidiary of Pioneer in Argentina (PNRA)
that is involved in various administrative proceedings with
environmental authorities in the Neuquén Province relating
to permits for and discharges from operations in that province.
In addition, PNRA was named in a suit initiated against oil
companies operating in the Neuquén basin entitled
Asociación de Superficiarios de la Patagonia v YPF S.A.,
et. al., originally filed on August 21, 2003, in the
Argentine National Supreme Court of Justice. The plaintiffs, a
private group of landowners, have also named the national
government and several provinces as third parties. The lawsuit
alleges injury to the environment generally by the oil and gas
industry. The plaintiffs principally seek from all defendants,
jointly, (i) the remediation of contaminated sites, of the
superficial and underground waters, and of soil that allegedly
was degraded as a result of deforestation, (ii) if the
remediation is not possible, payment of an indemnification for
the material and moral damages claimed from defendants operating
in the Neuquén basin, of which PNRA is a small portion,
(iii) adoption of all the necessary measures to prevent
future environmental damages, and (iv) the creation of a
private restoration fund to provide coverage for remediation of
potential future environmental damages. Much of the alleged
damage relates to operations by the Argentine state oil company,
which conducted oil and gas operations throughout Argentina
prior to its privatization, which began in 1990. While the
plaintiffs will seek to make all oil and gas companies operating
in the Neuquén basin jointly liable for each others
actions, PNRA will defend on an individual basis and attempt to
require the plaintiffs to delineate damages by company. PNRA
intends to defend itself vigorously in the case. It is not
certain exactly what the court will do in this matter as it is
the first of its kind. While it is possible PNRA may incur
liabilities related to the environmental claims, no reasonable
prediction can be made as PNRAs exposure related to this
lawsuit is not currently determinable.
Louisiana
Restoration
Numerous surface owners have filed claims or sent demand letters
to various oil and gas companies, including Apache, claiming
that, under either expressed or implied lease terms or Louisiana
law, they are liable for damage measured by the cost of
restoration of leased premises to their original condition as
well as damages from contamination and cleanup. Many of these
lawsuits claim small amounts, while others assert claims in
excess of $1 million. Also, some lawsuits or claims are
being settled or resolved, while others are still being filed.
Any exposure, therefore, related to these lawsuits and claims is
not currently determinable. While an adverse judgment against
Apache is possible, Apache intends to actively defend the cases.
Hurricane-Related
Litigation
In a case styled Ned Comer, et al vs. Murphy Oil USA, Inc.,
et al, Case No: 1:05-cv-00436; U.S.D.C., United States
District Court, Southern District of Mississippi, Mississippi
property owners allege that hurricanes meteorological
effects increased in frequency and intensity due to global
warming, and there will be continued
F-38
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
future damage from increasing intensity of storms and sea level
rises. They claim this was caused by the various defendants (oil
and gas companies, electric and coal companies, and chemical
manufacturers). Plaintiffs claim defendants emissions of
greenhouse gases cause global warming, which they
blame as the cause of their damages. They also claim that the
oil company defendants artificially inflated and manipulated the
prices of gasoline, diesel fuel, jet fuel, natural gas, and
other end-use petrochemicals, and covered it up by
misrepresentations. They further allege a conspiracy to
disseminate misinformation and cover up the relationship between
the defendants and global warming. Plaintiffs seek, among other
damages, actual, consequential, and punitive or exemplary
damages. The District Court dismissed the case on
August 30, 2007. The plaintiffs appealed the dismissal.
Prior to the dismissal, the plaintiffs filed a motion to amend
the lawsuit to add additional defendants, including Apache. On
October 16, 2009, the United States Court of Appeals for
the Fifth Circuit reversed the judgment of the District Court
and remanded the case to the District Court. The Fifth Circuit
held that plaintiffs have pleaded sufficient facts to
demonstrate standing for their public and private nuisance,
trespass, and negligence claims, and that those claims are
justifiable and do not present a political question. However,
the Fifth Circuit declined to find standing for the unjust
enrichment, civil conspiracy, and fraudulent misrepresentation
claims, and therefore dismissed those claims. Several defendants
filed a petition with the Fifth Circuit for a rehearing en
banc. In granting an appeal for an en banc hearing,
the U.S. Fifth Circuit Court of Appeals vacated an earlier
ruling by its three-member panel. That decision reinstated the
district judges dismissal of the lawsuit. Subsequently,
the Fifth Circuit Court of Appeals could not form a quorum to
hear the en banc appeal. Therefore, the court ruled that
its earlier order (vacating the panels ruling) stood,
which had the effect of dismissing the original lawsuit. The
U.S. Supreme Court has denied plaintiffs petition for
a writ of mandamus.
Australia
Gas Pipeline Force Majeure
The Company subsidiaries reported a pipeline explosion that
interrupted deliveries of natural gas to customers under various
long-term contracts. Company subsidiaries believe that the event
was a force majeure, and as a result, the subsidiaries and their
joint venture participants have declared force majeure under
those contracts. On December 16, 2009, a customer, Burrup
Fertilisers Pty Ltd, filed a lawsuit on behalf of itself and
certain of its underwriters at Lloyds of London and other
insurers, against the Company and its subsidiaries in Texas
state court, asserting claims for negligence, breach of
contract, alter ego, single business enterprise, res ipsa
loquitur, and gross negligence/exemplary damages. Other
customers have threatened to file suit challenging the
declaration of force majeure under their contracts. Contract
prices under their contracts are significantly below current
spot prices for natural gas in Australia. In the event it is
determined that the pipeline explosion was not a force majeure,
Company subsidiaries believe that liquidated damages should be
the extent of the damages under those long-term contracts with
such provisions. Approximately 90 percent of the natural
gas volumes sold by Company subsidiaries under long-term
contracts have liquidated damages provisions. Contractual
liquidated damages under the long-term contracts with such
provisions would not be expected to exceed $200 million
AUD. In their Harris County petition, Burrup Fertilisers and its
underwriters and insurers seek to recover unspecified actual
damages, cost of repair and replacement, exemplary damages, lost
profits, loss of business goodwill, value of the gas lost under
the GSA, interest and court costs. No assurance can be given
that Burrup Fertilisers and other customers would not assert
claims in excess of contractual liquidated damages, and exposure
related to such claims is not currently determinable. While an
adverse judgment against Company subsidiaries (and Company, in
the case of the Burrup Fertilisers lawsuit) is possible, the
Company and Company subsidiaries do not believe any such claims
would have merit and plan to vigorously pursue their defenses
against any such claims.
In December 2008 the Senate Economics Committee of the
Parliament of Australia released its findings from public
hearings concerning the economic impact of the gas shortage
following the explosion on Varanus Island and the
governments response. The Committee concluded, among other
things, that the macroeconomic impact to Western Australia will
never be precisely known, but cited to a range of estimates from
$300 million AUD to $2.5 billion AUD consisting in
part of losses alleged by some parties who have long-term
contracts with Company subsidiaries (as described above), but
also losses alleged by third parties who do not have contracts
with Company
F-39
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
subsidiaries (but who may have purchased gas that was re-sold by
customers or who may have paid more for energy following the
explosion or who lost wages or sales due to the inability to
obtain energy or the increased price of energy). A timber
industry group, whose members do not have a contract with
Company subsidiaries, has announced that it intends to seek
compensation for its members and their subcontractors from
Company subsidiaries for $20 million AUD in losses
allegedly incurred as a result of the gas supply shortage
following the explosion. In Johnson Tiles Pty Ltd v.
Esso Australia Pty Ltd [2003] VSC 27 (Supreme Court of
Victoria, Gillard J presiding), which concerned a 1998 explosion
at an Esso natural gas processing plant at Longford in East
Gippsland, Victoria, the Court held that Esso was not liable for
$1.3 billion AUD of pure economic losses suffered by
claimants that had no contract with Esso, but was liable to such
claimants for reasonably foreseeable property damage which Esso
settled for $32.5 million plus costs. In reaching this
decision the Court held that third-party claimants should have
protected themselves from pure economic losses, through the
purchase of insurance or the installation of adequate backup
measures, in case of an interruption in their gas supply from
Esso. While an adverse judgment against Company subsidiaries is
possible if litigation is filed, Company subsidiaries do not
believe any such claims would have merit and plan to vigorously
pursue their defenses against any such claims. Exposure related
to any such potential claims is not currently determinable.
On October 10, 2008, the Australia National Offshore
Petroleum Safety Authority (NOPSA) released a self-titled
Final Report of the findings of its investigation
into the pipeline explosion, prepared at the request of the
Western Australian Department of Industry and Resources (DoIR).
NOPSA concluded in its report that the evidence gathered to date
indicates that the main causal factors in the incident were:
(1) ineffective anti-corrosion coating at the beach
crossing section of the
12-inch
sales gas pipeline, due to damage
and/or
dis-bondment from the pipeline; (2) ineffective cathodic
protection of the wet-dry transition zone of the beach crossing
section of the
12-inch
sales gas pipeline; and (3) ineffective inspection and
monitoring by Company subsidiaries of the beach crossing and
shallow water section of the
12-inch
sales gas pipeline. NOPSA further concluded that the
investigation identified that Apache Northwest Pty Ltd and its
co-licensees may have committed offenses under the Petroleum
Pipelines Act 1969, Sections 36A & 38(b) and the
Petroleum Pipelines Regulations 1970, Regulation 10, and
that some findings may also constitute non-compliance with
pipeline license conditions. NOPSA states in its report that an
application for renewal of the pipeline license covering the
area of the Varanus Island facility was granted in May 1985 with
21 years validity, and an application for renewal of the
license was submitted to DoIR by Company subsidiaries in
December 2005 and remains pending.
Company subsidiaries disagree with NOPSAs conclusions and
believe that the NOPSA report is premature, based on an
incomplete investigation and misleading. In a July 17,
2008, media statement, DoIR acknowledged, The pipelines
and Varanus Island facilities have been the subject of an
independent validation report [by Lloyds Register] which
was received in August 2007. NOPSA has also undertaken a number
of inspections between 2005 and the present. These and
numerous other inspections, audits and reviews conducted by top
international consultants and regulators did not identify any
warnings that the pipeline had a corrosion problem or other
issues that could lead to its failure. Company subsidiaries
believe that the explosion was not reasonably foreseeable, and
was not within the reasonable control of Companys
subsidiaries or able to be reasonably prevented by Company
subsidiaries.
On January 9, 2009, the governments of Western Australia
and the Commonwealth of Australia announced a joint inquiry to
consider the effectiveness of the regulatory regime for
occupational health and safety and integrity that applied to
operations and facilities at Varanus Island and the role of
DoIR, NOPSA and the Western Australian Department of Consumer
and Employment Protection. The joint inquirys report was
published in June 2009.
On May 8, 2009, the government of Western Australia
announced that its Department of Mines and Petroleum (DMP) will
carry out the final stage of investigations into the
Varanus Island gas explosion. Inspectors were appointed
under the Petroleum Pipelines Act to coordinate the final stage
of the investigations. Their report has been delivered to the
Minister for Mines and Petroleum, but neither the report nor its
contents have been made available to Company subsidiaries for
their review and comment.
F-40
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On May 28, 2009, the DMP filed a prosecution notice in the
Magistrates Court of Western Australia, charging Apache
Northwest Pty Ltd and its co-licensees with failure to maintain
a pipeline in good condition and repair under the Petroleum
Pipelines Act 1969, Section 38(b). The maximum fine
associated with the alleged offense is $50,000 AUD. The Company
subsidiary does not believe that the charge has merit and plans
to vigorously pursue its defenses.
Mariner
Stockholder Lawsuits
In connection with the Merger, two shareholder lawsuits styled
as class actions have been filed against Mariner and its board
of directors. The lawsuits are entitled City of Livonia
Employees Retirement System, Individually and on Behalf of
All Others Similarly Situated vs. Mariner Energy, Inc, et al.,
(filed April 16, 2010, in the District Court of Harris
County, Texas), and Southeastern Pennsylvania Transportation
Authority, individually, and on behalf of all those similarly
situated, vs. Scott D. Josey, et.al., (filed
April 21, 2010, in the Court of Chancery in the State of
Delaware). The Southeastern Pennsylvania Transportation
Authority lawsuit also names Apache and its wholly owned
subsidiary, ZMZ Acquisitions LLC (the Merger Sub) as defendants.
The complaints generally allege that (1) Mariners
directors breached their fiduciary duties in negotiating and
approving the Merger and by administering a sale process that
failed to maximize shareholder value and (2) Mariner, and
in the case of the Southeastern Pennsylvania Transportation
Authority complaint, Apache and the Merger Sub, aided and
abetted Mariners directors in breaching their fiduciary
duties. The City of Livonia Employees Retirement System
complaint also alleges that Mariners directors and
executives stand to receive substantial financial benefits from
the transaction. Pending court approval, these lawsuits have
been settled in principle and are not expected to have a
material impact on Apache.
Escheat
Audits
The State of Delaware, Department of Finance, Division of
Revenue (Unclaimed Property), has notified numerous companies,
including Apache Corporation, that the State intends to examine
its books and records and those of its subsidiaries and related
entities to determine compliance with the Delaware Escheat Laws.
The review will be conducted by Kelmar Associates on behalf of
the State. At least 30 other states have retained their own
consultants and have sent similar notifications. The scope of
each states audit varies. The State of Delaware advises,
for example, that the scope of its examination will be for the
period 1981 through the present. It is possible that one or more
of the State audits could extend to all 50 states.
NAL GP
Ltd Lawsuit
In a lawsuit commenced on September 23, 2010, and styled as
NAL GP Ltd., Applicant, and BP Canada Energy Company, BP Canada
Energy, and Apache Corporation, Respondents, Action
No. 1001-14115,
in the Court of Queens Bench of Alberta, Judicial District
of Calgary, NAL GP Ltd. (NAL) seeks, among other
things, interim injunctive relief to freeze the
15-day
notice period concerning NALs rights of first refusal
relating to certain of the Canadian assets involved in the
transaction between BP and Apache announced July 20, 2010,
and further a hearing concerning the allocated values associated
with such assets (approximately $1.6 billion USD in the
aggregate). Apache Corporation was wrongly named as a respondent
in the proceeding, and so Apache Canada Ltd. has appeared in the
proceeding. A hearing on NALs application was held on
September 27, 2010. On September 28, 2010, the Court
dismissed NALs application in its entirety. NAL filed an
appeal. The parties have resolved the matter amicably, including
the dismissal of the lawsuit and discontinuance of the appeal,
which resolution did not have a material effect on the Company.
Environmental
Matters
The Company, as an owner or lessee and operator of oil and gas
properties, is subject to various federal, provincial, state,
local and foreign country laws and regulations relating to
discharge of materials into, and
F-41
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
protection of, the environment. These laws and regulations may,
among other things, impose liability on the lessee under an oil
and gas lease for the cost of pollution
clean-up
resulting from operations and subject to the lessee to liability
for pollution damages. In some instances, the Company may be
directed to suspend or cease operations in the affected area. We
maintain insurance coverage, which we believe is customary in
the industry, although we are not fully insured against all
environmental risks.
Apache manages its exposure to environmental liabilities on
properties to be acquired by identifying existing problems and
assessing the potential liability. The Company also conducts
periodic reviews, on a Company-wide basis, to identify changes
in its environmental risk profile. These reviews evaluate
whether there is a probable liability, the amount, and the
likelihood that the liability will be incurred. The amount of
any potential liability is determined by considering, among
other matters, incremental direct costs of any likely
remediation and the proportionate cost of employees who are
expected to devote a significant amount of time directly to any
possible remediation effort. As it relates to evaluations of
purchased properties, depending on the extent of an identified
environmental problem, the Company may exclude a property from
the acquisition, require the seller to remediate the property to
Apaches satisfaction, or agree to assume liability for the
remediation of the property. The Companys general policy
is to limit any reserve additions to any incidents or sites that
are considered probable to result in an expected remediation
cost exceeding $300,000. Any environmental costs and liabilities
that are not reserved for are treated as an expense when
actually incurred. In Apaches estimation, neither these
expenses nor expenses related to training and compliance
programs are likely to have a material impact on its financial
condition.
As of December 31, 2010, the Company had an undiscounted
reserve for environmental remediation of approximately
$135 million, of which approximately $109 million is
related to properties acquired in 2010. Apache is not aware of
any environmental claims existing as of December 31, 2010
that have not been provided for or would otherwise have a
material impact on its financial position or results of
operations. There can be no assurance however, that current
regulatory requirements will not change or past non-compliance
with environmental laws will not be discovered on the
Companys properties.
Apache Canada Ltd. has asserted a claim against BP Canada
arising out of the acquisition of certain Canadian properties
under the parties Partnership Interest and Share Purchase
and Sale Agreement dated July 20, 2010. The dispute centers
on Apache Canada Ltd.s identification of Alleged Adverse
Conditions, as that term is defined in the parties
agreement, and more specifically the contention that liabilities
associated with such conditions were retained by BP Canada as
seller. Apache Canada Ltd. is diligently pursuing this claim.
Retirement
and Deferred Compensation Plans
Apache Corporation provides retirement benefits to its
U.S. employees through the use of three types of plans: an
Internal Revenue Code (IRC) 401(k) savings plan, a money
purchase retirement plan and a restorative non-qualified
retirement savings plan. The 401(k) savings plan provides
participating employees the ability to elect to contribute up to
50 percent of eligible compensation to the plan with the
Company making matching contributions up to a maximum of six
percent of each employees annual covered compensation. In
addition, the Company annually contributes six percent of each
participating employees compensation, as defined, to a
money purchase retirement plan. The 401(k) plan and the money
purchase retirement plan are subject to certain
annually-adjusted, government-mandated restrictions that limit
the amount of employee and Company contributions. For certain
eligible employees, the Company also provides a non-qualified
retirement/savings plan that allows the deferral of up to
50 percent of each employees salary and that accepts
employee contributions and the Companys matching
contributions in excess of the government mandated limitations
imposed in the 401(k) savings plan and money purchase retirement
plan.
Vesting in the Companys contributions in the 401(k)
savings plan, the money purchase retirement plan and the
non-qualified retirement/savings plan occurs at the rate of
20 percent for every full year of employment. Upon a change
in control of ownership, immediate and full vesting occurs.
F-42
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Additionally, Apache Energy Limited, Apache Canada Ltd. and
Apache North Sea Limited maintain separate retirement plans, as
required under the laws of Australia, Canada and the United
Kingdom, respectively.
The aggregate annual cost of the 401(k) savings plans, the money
purchase retirement plan and the non-qualified
retirement/savings plans was $80 million, $66 million
and $52 million for 2010, 2009 and 2008, respectively.
Apache also provides a funded noncontributory defined benefit
pension plan (U.K. Pension Plan) covering certain employees of
the Companys North Sea operations in the United Kingdom
(U.K.). The plan provides defined pension benefits based on
years of service and final average salary. The plan applies only
to employees who were part of the BP North Seas pension
plan as of April 2, 2003, prior to the acquisition of BP
North Sea by the Company effective July 1, 2003.
Additionally, the Company offers postretirement medical benefits
to U.S. employees who meet certain eligibility
requirements. Covered participants receive medical benefits up
until the age of 65 or the Medicare eligibility date, if later,
provided the participant remits the required portion of the cost
of coverage. The plan is contributory with participants
contributions adjusted annually. The postretirement benefit plan
does not cover benefit expenses once a covered participant
becomes eligible for Medicare.
F-43
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following tables set forth the benefit obligation, fair
value of plan assets and funded status as of December 31,
2010, 2009 and 2008, and the underlying weighted average
actuarial assumptions used for the U.K. Pension Plan and
U.S. postretirement benefit plan. Apache uses a measurement
date of December 31 for its pension and postretirement benefit
plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
Pension
|
|
|
Postretirement
|
|
|
Pension
|
|
|
Postretirement
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
Benefits
|
|
|
Benefits
|
|
|
Benefits
|
|
|
Benefits
|
|
|
Benefits
|
|
|
|
(In millions)
|
|
|
Change in Projected Benefit Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation beginning of year
|
|
$
|
135
|
|
|
$
|
18
|
|
|
$
|
99
|
|
|
$
|
17
|
|
|
$
|
130
|
|
|
$
|
14
|
|
Service cost
|
|
|
5
|
|
|
|
2
|
|
|
|
4
|
|
|
|
2
|
|
|
|
6
|
|
|
|
2
|
|
Interest cost
|
|
|
7
|
|
|
|
1
|
|
|
|
6
|
|
|
|
1
|
|
|
|
7
|
|
|
|
1
|
|
Foreign currency exchange rate changes
|
|
|
(4
|
)
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
(38
|
)
|
|
|
|
|
Amendments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial losses (gains)
|
|
|
(1
|
)
|
|
|
8
|
|
|
|
17
|
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
|
|
Effect of curtailment and settlements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefits paid
|
|
|
(6
|
)
|
|
|
|
|
|
|
(4
|
)
|
|
|
(1
|
)
|
|
|
(4
|
)
|
|
|
|
|
Retiree contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation at end of year
|
|
|
136
|
|
|
|
29
|
|
|
|
135
|
|
|
|
18
|
|
|
|
99
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Plan Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
|
118
|
|
|
|
|
|
|
|
83
|
|
|
|
|
|
|
|
122
|
|
|
|
|
|
Actual return on plan assets
|
|
|
14
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
(13
|
)
|
|
|
|
|
Foreign currency exchange rates
|
|
|
(3
|
)
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
(32
|
)
|
|
|
|
|
Employer contributions
|
|
|
12
|
|
|
|
|
|
|
|
16
|
|
|
|
1
|
|
|
|
10
|
|
|
|
|
|
Benefits paid
|
|
|
(6
|
)
|
|
|
|
|
|
|
(4
|
)
|
|
|
(1
|
)
|
|
|
(4
|
)
|
|
|
|
|
Retiree contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year
|
|
|
135
|
|
|
|
|
|
|
|
118
|
|
|
|
|
|
|
|
83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status at end of year
|
|
$
|
(1
|
)
|
|
$
|
(29
|
)
|
|
$
|
(17
|
)
|
|
$
|
(18
|
)
|
|
$
|
(17
|
)
|
|
$
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts recognized in Consolidated Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liability
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
Non-current liability
|
|
|
(1
|
)
|
|
|
(28
|
)
|
|
|
(17
|
)
|
|
|
(17
|
)
|
|
|
(17
|
)
|
|
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1
|
)
|
|
$
|
(29
|
)
|
|
$
|
(17
|
)
|
|
$
|
(18
|
)
|
|
$
|
(17
|
)
|
|
$
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pretax Amounts Recognized in Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated gain (loss)
|
|
|
(15
|
)
|
|
|
(8
|
)
|
|
|
(24
|
)
|
|
|
|
|
|
|
(14
|
)
|
|
|
|
|
Prior service cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transition asset (obligation)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(15
|
)
|
|
$
|
(8
|
)
|
|
$
|
(24
|
)
|
|
$
|
|
|
|
$
|
(14
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Assumptions used as of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
5.40
|
%
|
|
|
4.93
|
%
|
|
|
5.70
|
%
|
|
|
5.56
|
%
|
|
|
5.50
|
%
|
|
|
6.03
|
%
|
Salary increases
|
|
|
5.00
|
%
|
|
|
N/A
|
|
|
|
5.30
|
%
|
|
|
N/A
|
|
|
|
4.50
|
%
|
|
|
N/A
|
|
Expected return on assets
|
|
|
6.25
|
%
|
|
|
N/A
|
|
|
|
6.65
|
%
|
|
|
N/A
|
|
|
|
6.05
|
%
|
|
|
N/A
|
|
Healthcare cost trend
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Initial
|
|
|
N/A
|
|
|
|
8.00
|
%
|
|
|
N/A
|
|
|
|
7.50
|
%
|
|
|
N/A
|
|
|
|
8.00
|
%
|
Ultimate in 2015
|
|
|
N/A
|
|
|
|
5.00
|
%
|
|
|
N/A
|
|
|
|
5.00
|
%
|
|
|
N/A
|
|
|
|
5.00
|
%
|
As of December 31, 2010, 2009 and 2008, the accumulated
benefit obligation for the pension plan was $107 million,
$89 million and $69 million, respectively.
F-44
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Apaches defined benefit pension plan assets are held by a
non-related trustee who has been instructed to invest the assets
in an equal blend of equity securities and low-risk debt
securities. The Company intends that this blend of investments
will provide a reasonable rate of return such that the benefits
promised to members are provided.
The U.K. Pension Plan policy is to target an ongoing funding
level of 100 percent through prudent investments and
includes policies and strategies such as investment goals, risk
management practices and permitted and prohibited investments.
A
breakout of previous allocations for plan asset holding and the
target allocation for the Companys plan assets are
summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of
|
|
|
|
|
|
|
Plan Assets at
|
|
|
|
Target Allocation
|
|
|
Year-End
|
|
|
|
2010
|
|
|
2010
|
|
|
2009
|
|
|
Asset Category
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.K. quoted equities
|
|
|
17
|
%
|
|
|
18
|
%
|
|
|
28
|
%
|
Overseas quoted equities
|
|
|
33
|
%
|
|
|
34
|
%
|
|
|
19
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity securities
|
|
|
50
|
%
|
|
|
52
|
%
|
|
|
47
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.K. Government bonds
|
|
|
36
|
%
|
|
|
31
|
%
|
|
|
31
|
%
|
U.K. corporate bonds
|
|
|
14
|
%
|
|
|
17
|
%
|
|
|
18
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities
|
|
|
50
|
%
|
|
|
48
|
%
|
|
|
49
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
|
|
|
|
|
|
|
|
|
4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The plans assets do not include any equity or debt
securities of Apache. The fair value of plan assets is based
upon unadjusted quoted prices for identical instruments in
active markets, which is a Level 1 fair value measurement.
See discussion of the fair value hierarchy as set forth by
ASC 820-10-35
in Note 9 Fair Value Measurements.
The
following table presents the fair values of plan assets for each
major asset category based on the nature and significant
concentration of risks in plan assets at December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
|
|
|
|
|
Quoted Price
|
|
|
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Significant
|
|
|
Unobservable
|
|
|
|
|
|
|
Markets
|
|
|
Other Inputs
|
|
|
Inputs
|
|
|
Total Fair
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Value
|
|
|
|
(In millions)
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.K. quoted equities(1)
|
|
$
|
24
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
24
|
|
Overseas quoted equities(2)
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity securities
|
|
|
70
|
|
|
|
|
|
|
|
|
|
|
|
70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.K. Government bonds(3)
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
42
|
|
U.K. corporate bonds(4)
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt securities
|
|
|
65
|
|
|
|
|
|
|
|
|
|
|
|
65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets
|
|
$
|
135
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-45
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(1) |
|
This category comprises U.K. equities, which are benchmarked
against the FTSE All-Share Index. |
|
(2) |
|
This category includes overseas equities, which comprises
85 percent global equities benchmarked against the MSCI
World Index and 15 percent emerging markets benchmarked
against the MSCI Emerging Markets Index, both of which have a
performance target of 2 percent per annum over the
benchmark over a rolling three-year period. |
|
(3) |
|
This category includes U.K. Government bonds: 72 percent
benchmarked against iBoxx Sterling Overall Index, with a
performance target of 0.75 percent per annum over the
benchmark over a rolling three-year period; and 28 percent
against the FTSE Actuaries Government Securities Index-Linked
Over 5 Years Index. |
|
(4) |
|
This category comprises U.K. corporate bonds benchmarked against
the iBoxx Sterling Overall Index. |
The expected long-term rate of return on assets assumptions are
derived relative to the yield on long-dated fixed-interest bonds
issued by the U.K. government (gilts). For equities,
outperformance relative to gilts is assumed to be
3.5 percent per year.
The following table presents the fair values of plan assets for
each major asset category based on the nature and significant
concentration of risks in plan assets at December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
|
|
|
|
|
Quoted Price
|
|
|
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Significant
|
|
|
Unobservable
|
|
|
|
|
|
|
Markets
|
|
|
Other Inputs
|
|
|
Inputs
|
|
|
Total Fair
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Value
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.K. quoted equities(1)
|
|
$
|
34
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
34
|
|
Overseas quoted equities(2)
|
|
|
22
|
|
|
|
|
|
|
|
|
|
|
|
22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity securities
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.K. Government bonds(3)
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
U.K. corporate bonds(4)
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt securities
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets
|
|
$
|
118
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
This category comprises U.K. equities, which are benchmarked
against the FTSE All-Share Index. |
|
(2) |
|
This category includes overseas equities: 40 percent
benchmarked against the FTSE Europe ex UK Index; 30 percent
against the FTSE North America Index; 20 percent against
the FTSE Japan Index; and 10 percent against the FTSE Asia
Pacific ex Japan Index. |
|
(3) |
|
This category includes U.K. Government bonds: 67 percent
benchmarked against the FTSE A British Government Over
15 Years Index; 16.5 percent against the FTSE
Actuaries Government Securities Over 15 Years Gilt Index;
and 16.5 percent against the FTSE Actuaries Government
Securities Index-Linked Over 5 Years Index. |
|
(4) |
|
This category comprises U.K. corporate bonds benchmarked against
the iBoxx £ Non Gilt Over 10 Years Index. |
The expected long-term rate of return on assets assumptions are
derived relative to the yield on long-dated fixed-interest bonds
issued by the U.K. government (gilts). For equities,
outperformance relative to gilts is assumed to be
3.5 percent per year.
F-46
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following tables set forth the components of the net
periodic cost and the underlying weighted average actuarial
assumptions used for the pension and postretirement benefit
plans as of December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
Pension
|
|
|
Postretirement
|
|
|
Pension
|
|
|
Postretirement
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
Benefits
|
|
|
Benefits
|
|
|
Benefits
|
|
|
Benefits
|
|
|
Benefits
|
|
|
|
(In millions)
|
|
|
Components of Net Periodic Benefit Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
5
|
|
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
2
|
|
|
$
|
6
|
|
|
$
|
2
|
|
Interest cost
|
|
|
7
|
|
|
|
1
|
|
|
|
6
|
|
|
|
1
|
|
|
|
7
|
|
|
|
1
|
|
Expected return on assets
|
|
|
(8
|
)
|
|
|
|
|
|
|
(6
|
)
|
|
|
|
|
|
|
(8
|
)
|
|
|
|
|
Amortization of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transition obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial (gain) loss
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost
|
|
$
|
5
|
|
|
$
|
3
|
|
|
$
|
4
|
|
|
$
|
3
|
|
|
$
|
5
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Assumptions used to determine Net Periodic
Benefit Costs for the Years ended December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
5.7
|
%
|
|
|
5.56
|
%
|
|
|
5.50
|
%
|
|
|
6.03
|
%
|
|
|
5.60
|
%
|
|
|
6.01
|
%
|
Salary increases
|
|
|
5.3
|
%
|
|
|
N/A
|
|
|
|
4.50
|
%
|
|
|
N/A
|
|
|
|
4.40
|
%
|
|
|
N/A
|
|
Expected return on assets
|
|
|
6.65
|
%
|
|
|
N/A
|
|
|
|
6.05
|
%
|
|
|
N/A
|
|
|
|
6.50
|
%
|
|
|
N/A
|
|
Healthcare cost trend
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Initial
|
|
|
|
|
|
|
7.50
|
%
|
|
|
|
|
|
|
8.00
|
%
|
|
|
|
|
|
|
8.00
|
%
|
Ultimate in 2014
|
|
|
|
|
|
|
5.00
|
%
|
|
|
|
|
|
|
5.00
|
%
|
|
|
|
|
|
|
5.00
|
%
|
Assumed health care cost trend rates effect amounts reported for
postretirement benefits. A one-percentage-point change in
assumed health care cost trend rates would have the following
effects:
|
|
|
|
|
|
|
|
|
|
|
Postretirement Benefits
|
|
|
1% Increase
|
|
1% Decrease
|
|
|
(In millions)
|
|
Effect on service and interest cost components
|
|
$
|
|
|
|
$
|
|
|
Effect on postretirement benefit obligation
|
|
|
3
|
|
|
|
(3
|
)
|
Apache expects to contribute approximately $11 million to
its pension plan and $546,000 to its postretirement benefit plan
in 2011. The following benefit payments, which reflect expected
future service, as appropriate, are expected to be paid:
|
|
|
|
|
|
|
|
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
Benefits
|
|
|
|
(In millions)
|
|
|
2011
|
|
|
4
|
|
|
|
1
|
|
2012
|
|
|
3
|
|
|
|
1
|
|
2013
|
|
|
5
|
|
|
|
2
|
|
2014
|
|
|
6
|
|
|
|
2
|
|
2015
|
|
|
6
|
|
|
|
2
|
|
Years 2016 2020
|
|
|
39
|
|
|
|
18
|
|
F-47
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Contractual
Obligations
At December 31, 2010, contractual obligations for drilling
rigs, purchase obligations, exploration and development
(E&D) commitments, firm transportation agreements, and
long-term operating leases ranging from one to 26 years,
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Minimum Commitments
|
|
Total
|
|
|
2011
|
|
|
2012-2014
|
|
|
2015-2016
|
|
|
2017 & Beyond
|
|
|
|
(In millions)
|
|
|
Drilling rig commitments(1)
|
|
$
|
392
|
|
|
$
|
303
|
|
|
$
|
89
|
|
|
$
|
|
|
|
$
|
|
|
Purchase obligations(2)
|
|
|
833
|
|
|
|
574
|
|
|
|
259
|
|
|
|
|
|
|
|
|
|
E&D commitments(3)
|
|
|
575
|
|
|
|
235
|
|
|
|
308
|
|
|
|
32
|
|
|
|
|
|
Firm transportation agreements(4)
|
|
|
809
|
|
|
|
138
|
|
|
|
423
|
|
|
|
170
|
|
|
|
78
|
|
Office and related equipment(5)
|
|
|
166
|
|
|
|
34
|
|
|
|
70
|
|
|
|
25
|
|
|
|
37
|
|
Oil and gas operations equipment(6)
|
|
|
476
|
|
|
|
85
|
|
|
|
146
|
|
|
|
55
|
|
|
|
190
|
|
Other
|
|
|
5
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Minimum Commitments
|
|
$
|
3,256
|
|
|
$
|
1,374
|
|
|
$
|
1,295
|
|
|
$
|
282
|
|
|
$
|
305
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes day-rate and other contracts for use of drilling,
completion and workover rigs. |
|
(2) |
|
Include contractual obligations to buy or build oil and gas
plants and facilities. |
|
(3) |
|
Generally consists of seismic and drilling work programs
required to retain acreage, meet contractual obligations of
international concessions, or to satisfy minimum investments
associated with farm-in properties. |
|
(4) |
|
Relates to contractual obligations for capacity rights on
third-party pipelines. |
|
(5) |
|
Includes office and other building rentals and related equipment
leases. |
|
(6) |
|
Includes floating production storage and offloading (FPSOs),
compressors, helicopters and boats. |
The table above includes leases for buildings, facilities and
related equipment with varying expiration dates through 2035.
Net rental expense was $46 million, $38 million and
$38 million for 2010, 2009 and 2008, respectively.
|
|
9.
|
FAIR
VALUE MEASUREMENTS
|
ASC
820-10-35
provides a hierarchy that prioritizes and defines the types of
inputs used to measure fair value. The fair value hierarchy
gives the highest priority to Level 1 inputs, which consist
of unadjusted quoted prices for identical instruments in active
markets. Level 2 inputs consist of quoted prices for
similar instruments. Level 3 valuations are derived from
inputs that are significant and unobservable; hence, these
valuations have the lowest priority.
The valuation techniques that may be used to measure fair value
include a market approach, an income approach, and a cost
approach. A market approach uses prices and other relevant
information generated by market transactions involving identical
or comparable assets or liabilities. An income approach uses
valuation techniques to convert future amounts to a single
present amount based on current market expectations, including
present value techniques, option-pricing models and excess
earnings method. The cost approach is based on the amount that
currently would be required to replace the service capacity of
an asset (replacement cost).
F-48
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Assets
and Liabilities Measured at Fair Value on a Recurring
Basis
Certain assets and liabilities are reported at fair value on a
recurring basis in Apaches consolidated balance sheet. The
following methods and assumptions were used to estimate the fair
values:
Cash,
Cash Equivalents, Short-Term Investments, Accounts Receivable
and Accounts Payable
The carrying amounts approximate fair value because of the
short-term nature or maturity of the instruments.
Commodity
Derivative Instruments
Apaches commodity derivative instruments consist of
variable-to-fixed
price commodity swaps and options. The fair values of the
Companys derivative instruments are not actively quoted in
the open market. The Company uses a market approach to estimate
the fair values of its derivative instruments, utilizing
commodity futures price strips for the underlying commodities
provided by a reputable third-party. These valuations are
Level 2 inputs. For further information regarding
Apaches derivative instruments and hedging activities,
please see Note 3 Derivative Instruments and
Hedging Activities.
The following table presents the Companys material assets
and liabilities measured at fair value on a recurring basis for
each hierarchy level:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Price
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Significant
|
|
|
Unobservable
|
|
|
|
|
|
|
|
|
|
|
|
|
Markets
|
|
|
Other Inputs
|
|
|
Inputs
|
|
|
Total Fair
|
|
|
|
|
|
Carrying
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Value
|
|
|
Netting(1)
|
|
|
Amount
|
|
|
|
(In millions)
|
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivative Instruments
|
|
$
|
|
|
|
$
|
454
|
|
|
$
|
|
|
|
$
|
454
|
|
|
$
|
(148
|
)
|
|
$
|
306
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivative Instruments
|
|
|
|
|
|
|
466
|
|
|
|
|
|
|
|
466
|
|
|
|
(148
|
)
|
|
|
318
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivative Instruments
|
|
$
|
|
|
|
$
|
75
|
|
|
$
|
|
|
|
$
|
75
|
|
|
$
|
(11
|
)
|
|
$
|
64
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivative Instruments
|
|
|
|
|
|
|
341
|
|
|
|
|
|
|
|
341
|
|
|
|
(11
|
)
|
|
|
330
|
|
|
|
|
(1) |
|
The derivative fair values above are based on analysis of each
contract as required by ASC Topic 820. Derivative assets and
liabilities with the same counterparty are presented here on a
gross basis, even where the legal right of offset exists. For a
discussion of net amounts recorded on the consolidated balance
sheet at December 31, 2010 and 2009, please see
Note 3 Derivative Instruments and Hedging
Activities. |
Assets
and Liabilities Measured at Fair Value on a Nonrecurring
Basis
Certain assets and liabilities are reported at fair value on a
nonrecurring basis in Apaches consolidated balance sheet.
The following methods and assumptions were used to estimate fair
values:
Asset
Retirement Obligations Incurred in Current Period
Apache uses an income approach to estimate the fair value of
AROs based on discounted cash flow projections using numerous
estimates, assumptions and judgments regarding such factors as
the existence of a legal obligation for an ARO; estimated
probabilities, amounts and timing of settlements; the
credit-adjusted risk-free rate to be used; and inflation rates.
AROs incurred in the current period were Level 3 fair value
measurements. A summary of changes in the ARO liability is
provided in Note 4 Asset Retirement Obligation.
F-49
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Debt
The Companys debt is recorded at the carrying amount on
its consolidated balance sheet. For further discussion of the
Companys debt, please see Note 5 Debt.
Apache uses a market approach to determine the fair value of its
fixed-rate debt using estimates provided by an independent
investment financial data services firm, which is a Level 2
fair value measurement. The carrying amount of floating-rate
debt approximates fair value because the interest rates are
variable and reflective of market rates.
The
following table presents the carrying amounts and estimated fair
values of the Companys debt at December 31, 2010 and
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
December 31, 2009
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(In millions)
|
|
|
Money market lines of credit
|
|
$
|
46
|
|
|
$
|
46
|
|
|
$
|
7
|
|
|
$
|
7
|
|
Commercial paper
|
|
|
913
|
|
|
|
913
|
|
|
|
|
|
|
|
|
|
Notes and debentures
|
|
|
7,182
|
|
|
|
7,870
|
|
|
|
5,060
|
|
|
|
5,628
|
|
The carrying amount of the Companys money market lines of
credit and commercial paper approximate fair value because the
interest rates are variable and reflective of market rates. The
Companys trade payables and short-term investments are, by
their very nature, short-term. The carrying values of these
items included in the accompanying consolidated balance sheet
approximate fair value at December 31, 2010 and 2009.
In 2010, 2009 and 2008, purchases by Shell accounted for
15 percent, 18 percent and 17 percent,
respectively, of the Companys worldwide oil and gas
production revenues.
F-50
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
11.
|
BUSINESS
SEGMENT INFORMATION
|
Apache is engaged in a single line of business. Both
domestically and internationally, the Company explores for,
develops and produces natural gas, crude oil and natural gas
liquids. At December 31, 2010, the Company had production
in six countries: the United States, Canada, Egypt, Australia,
offshore the U.K. in the North Sea and Argentina. Apache also
has exploration interest on the Chilean side of the island of
Tierra del Fuego. Financial information for each country is
presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Egypt
|
|
|
Australia
|
|
|
Sea
|
|
|
Argentina
|
|
|
International
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues
|
|
$
|
4,300
|
|
|
$
|
1,074
|
|
|
$
|
3,372
|
|
|
$
|
1,459
|
|
|
$
|
1,606
|
|
|
$
|
372
|
|
|
$
|
|
|
|
$
|
12,183
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring
|
|
|
1,163
|
|
|
|
294
|
|
|
|
754
|
|
|
|
408
|
|
|
|
304
|
|
|
|
160
|
|
|
|
|
|
|
|
3,083
|
|
Additional
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation accretion
|
|
|
62
|
|
|
|
23
|
|
|
|
|
|
|
|
9
|
|
|
|
15
|
|
|
|
2
|
|
|
|
|
|
|
|
111
|
|
Lease operating expenses
|
|
|
924
|
|
|
|
334
|
|
|
|
298
|
|
|
|
185
|
|
|
|
168
|
|
|
|
123
|
|
|
|
|
|
|
|
2,032
|
|
Gathering and transportation
|
|
|
42
|
|
|
|
75
|
|
|
|
31
|
|
|
|
|
|
|
|
25
|
|
|
|
5
|
|
|
|
|
|
|
|
178
|
|
Taxes other than income
|
|
|
190
|
|
|
|
35
|
|
|
|
10
|
|
|
|
11
|
|
|
|
422
|
|
|
|
22
|
|
|
|
|
|
|
|
690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)(1)
|
|
$
|
1,919
|
|
|
$
|
313
|
|
|
$
|
2,279
|
|
|
$
|
846
|
|
|
$
|
672
|
|
|
$
|
60
|
|
|
$
|
|
|
|
|
6,089
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(91
|
)
|
General and administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(380
|
)
|
Merger, Acquisitions & Transition
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(183
|
)
|
Financing costs, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(229
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Property and Equipment
|
|
$
|
19,069
|
|
|
$
|
7,497
|
|
|
$
|
4,726
|
|
|
$
|
3,495
|
|
|
$
|
1,970
|
|
|
$
|
1,336
|
|
|
$
|
58
|
|
|
$
|
38,151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
21,326
|
|
|
$
|
8,273
|
|
|
$
|
6,036
|
|
|
$
|
3,831
|
|
|
$
|
2,362
|
|
|
$
|
1,537
|
|
|
$
|
60
|
|
|
$
|
43,425
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to Net Property and Equipment
|
|
$
|
10,371
|
|
|
$
|
5,277
|
|
|
$
|
1,569
|
|
|
$
|
925
|
|
|
$
|
620
|
|
|
$
|
274
|
|
|
$
|
20
|
|
|
$
|
19,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues
|
|
$
|
3,050
|
|
|
$
|
877
|
|
|
$
|
2,553
|
|
|
$
|
363
|
|
|
$
|
1,369
|
|
|
$
|
362
|
|
|
$
|
|
|
|
$
|
8,574
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring
|
|
|
947
|
|
|
|
257
|
|
|
|
578
|
|
|
|
204
|
|
|
|
260
|
|
|
|
149
|
|
|
|
|
|
|
|
2,395
|
|
Additional
|
|
|
1,222
|
|
|
|
1,596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,818
|
|
Asset retirement obligation accretion
|
|
|
63
|
|
|
|
19
|
|
|
|
|
|
|
|
6
|
|
|
|
14
|
|
|
|
3
|
|
|
|
|
|
|
|
105
|
|
Lease operating expenses
|
|
|
762
|
|
|
|
269
|
|
|
|
264
|
|
|
|
101
|
|
|
|
158
|
|
|
|
108
|
|
|
|
|
|
|
|
1,662
|
|
Gathering and transportation
|
|
|
36
|
|
|
|
53
|
|
|
|
23
|
|
|
|
|
|
|
|
26
|
|
|
|
5
|
|
|
|
|
|
|
|
143
|
|
Taxes other than income
|
|
|
121
|
|
|
|
43
|
|
|
|
9
|
|
|
|
10
|
|
|
|
383
|
|
|
|
14
|
|
|
|
|
|
|
|
580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)(1)
|
|
$
|
(101
|
)
|
|
$
|
(1,360
|
)
|
|
$
|
1,679
|
|
|
$
|
42
|
|
|
$
|
528
|
|
|
$
|
83
|
|
|
$
|
|
|
|
|
871
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41
|
|
General and administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(344
|
)
|
Financing costs, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(242
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Property and Equipment
|
|
$
|
9,859
|
|
|
$
|
3,251
|
|
|
$
|
3,910
|
|
|
$
|
2,965
|
|
|
$
|
1,655
|
|
|
$
|
1,223
|
|
|
$
|
38
|
|
|
$
|
22,901
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
11,526
|
|
|
$
|
3,776
|
|
|
$
|
5,626
|
|
|
$
|
3,346
|
|
|
$
|
2,444
|
|
|
$
|
1,428
|
|
|
$
|
40
|
|
|
$
|
28,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to Net Property and Equipment
|
|
$
|
1,342
|
|
|
$
|
604
|
|
|
$
|
873
|
|
|
$
|
774
|
|
|
$
|
379
|
|
|
$
|
171
|
|
|
$
|
11
|
|
|
$
|
4,154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-51
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Egypt
|
|
|
Australia
|
|
|
Sea
|
|
|
Argentina
|
|
|
International
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues
|
|
$
|
5,083
|
|
|
$
|
1,651
|
|
|
$
|
2,739
|
|
|
$
|
372
|
|
|
$
|
2,103
|
|
|
$
|
380
|
|
|
$
|
|
|
|
$
|
12,328
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring
|
|
|
1,113
|
|
|
|
417
|
|
|
|
397
|
|
|
|
135
|
|
|
|
263
|
|
|
|
191
|
|
|
|
|
|
|
|
2,516
|
|
Additional
|
|
|
2,667
|
|
|
|
1,689
|
|
|
|
|
|
|
|
|
|
|
|
569
|
|
|
|
409
|
|
|
|
|
|
|
|
5,334
|
|
Asset retirement obligation accretion
|
|
|
66
|
|
|
|
14
|
|
|
|
|
|
|
|
6
|
|
|
|
13
|
|
|
|
2
|
|
|
|
|
|
|
|
101
|
|
Lease operating expenses
|
|
|
926
|
|
|
|
337
|
|
|
|
241
|
|
|
|
104
|
|
|
|
191
|
|
|
|
111
|
|
|
|
|
|
|
|
1,910
|
|
Gathering and transportation
|
|
|
40
|
|
|
|
63
|
|
|
|
21
|
|
|
|
|
|
|
|
28
|
|
|
|
5
|
|
|
|
|
|
|
|
157
|
|
Taxes other than income
|
|
|
212
|
|
|
|
43
|
|
|
|
8
|
|
|
|
11
|
|
|
|
695
|
|
|
|
16
|
|
|
|
|
|
|
|
985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)(1)
|
|
$
|
59
|
|
|
$
|
(912
|
)
|
|
$
|
2,072
|
|
|
$
|
116
|
|
|
$
|
344
|
|
|
$
|
(354
|
)
|
|
$
|
|
|
|
|
1,325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62
|
|
General and administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(289
|
)
|
Financing costs, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(166
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
932
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Property and Equipment
|
|
$
|
10,686
|
|
|
$
|
4,500
|
|
|
$
|
3,615
|
|
|
$
|
2,394
|
|
|
$
|
1,536
|
|
|
$
|
1,200
|
|
|
$
|
28
|
|
|
$
|
23,959
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
11,976
|
|
|
$
|
5,846
|
|
|
$
|
4,968
|
|
|
$
|
2,626
|
|
|
$
|
2,287
|
|
|
$
|
1,446
|
|
|
$
|
37
|
|
|
$
|
29,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to Net Property and Equipment
|
|
$
|
2,748
|
|
|
$
|
872
|
|
|
$
|
1,452
|
|
|
$
|
938
|
|
|
$
|
479
|
|
|
$
|
363
|
|
|
$
|
27
|
|
|
$
|
6,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Operating Income consists of oil and gas production revenues
less depreciation, depletion and amortization, asset retirement
obligation accretion, lease operating expenses, gathering and
transportation costs, and taxes other than income. |
F-52
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
12.
|
SUPPLEMENTAL
OIL AND GAS DISCLOSURES (Unaudited)
|
Oil
and Gas Operations
The following table sets forth revenue and direct cost
information relating to the Companys oil and gas
exploration and production activities. Apache has no long-term
agreements to purchase oil or gas production from foreign
governments or authorities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Egypt
|
|
|
Australia
|
|
|
North Sea
|
|
|
Argentina
|
|
|
International
|
|
|
Total
|
|
|
|
(In millions, except per boe)
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues
|
|
$
|
4,300
|
|
|
$
|
1,074
|
|
|
$
|
3,372
|
|
|
$
|
1,459
|
|
|
$
|
1,606
|
|
|
$
|
372
|
|
|
$
|
|
|
|
$
|
12,183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring(1)
|
|
|
1,126
|
|
|
|
287
|
|
|
|
754
|
|
|
|
403
|
|
|
|
301
|
|
|
|
157
|
|
|
|
|
|
|
|
3,028
|
|
Additional
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation accretion
|
|
|
62
|
|
|
|
23
|
|
|
|
|
|
|
|
9
|
|
|
|
15
|
|
|
|
2
|
|
|
|
|
|
|
|
111
|
|
Lease operating expenses
|
|
|
924
|
|
|
|
334
|
|
|
|
298
|
|
|
|
185
|
|
|
|
168
|
|
|
|
123
|
|
|
|
|
|
|
|
2,032
|
|
Gathering and transportation
|
|
|
42
|
|
|
|
75
|
|
|
|
31
|
|
|
|
|
|
|
|
25
|
|
|
|
5
|
|
|
|
|
|
|
|
178
|
|
Production taxes(2)
|
|
|
177
|
|
|
|
31
|
|
|
|
|
|
|
|
11
|
|
|
|
423
|
|
|
|
14
|
|
|
|
|
|
|
|
656
|
|
Income tax
|
|
|
699
|
|
|
|
82
|
|
|
|
1,099
|
|
|
|
255
|
|
|
|
337
|
|
|
|
25
|
|
|
|
|
|
|
|
2,497
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,030
|
|
|
|
832
|
|
|
|
2,182
|
|
|
|
863
|
|
|
|
1,269
|
|
|
|
326
|
|
|
|
|
|
|
|
8,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
1,270
|
|
|
$
|
242
|
|
|
$
|
1,190
|
|
|
$
|
596
|
|
|
$
|
337
|
|
|
$
|
46
|
|
|
$
|
|
|
|
$
|
3,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization rate per boe
|
|
$
|
13.23
|
|
|
$
|
8.13
|
|
|
$
|
11.05
|
|
|
$
|
13.38
|
|
|
$
|
14.42
|
|
|
$
|
9.56
|
|
|
$
|
|
|
|
$
|
11.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues
|
|
$
|
3,050
|
|
|
$
|
877
|
|
|
$
|
2,553
|
|
|
$
|
363
|
|
|
$
|
1,369
|
|
|
$
|
362
|
|
|
$
|
|
|
|
$
|
8,574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring(1)
|
|
|
915
|
|
|
|
250
|
|
|
|
578
|
|
|
|
202
|
|
|
|
256
|
|
|
|
147
|
|
|
|
|
|
|
|
2,348
|
|
Additional
|
|
|
1,222
|
|
|
|
1,596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,818
|
|
Asset retirement obligation accretion
|
|
|
63
|
|
|
|
19
|
|
|
|
|
|
|
|
6
|
|
|
|
14
|
|
|
|
3
|
|
|
|
|
|
|
|
105
|
|
Lease operating expenses
|
|
|
762
|
|
|
|
269
|
|
|
|
264
|
|
|
|
101
|
|
|
|
158
|
|
|
|
108
|
|
|
|
|
|
|
|
1,662
|
|
Gathering and transportation
|
|
|
36
|
|
|
|
53
|
|
|
|
23
|
|
|
|
|
|
|
|
26
|
|
|
|
5
|
|
|
|
|
|
|
|
143
|
|
Production taxes(2)
|
|
|
107
|
|
|
|
35
|
|
|
|
|
|
|
|
10
|
|
|
|
383
|
|
|
|
7
|
|
|
|
|
|
|
|
542
|
|
Income tax
|
|
|
(19
|
)
|
|
|
(336
|
)
|
|
|
810
|
|
|
|
14
|
|
|
|
266
|
|
|
|
32
|
|
|
|
|
|
|
|
767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,086
|
|
|
|
1,886
|
|
|
|
1,675
|
|
|
|
333
|
|
|
|
1,103
|
|
|
|
302
|
|
|
|
|
|
|
|
8,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
(36
|
)
|
|
$
|
(1,009
|
)
|
|
$
|
878
|
|
|
$
|
30
|
|
|
$
|
266
|
|
|
$
|
60
|
|
|
$
|
|
|
|
$
|
189
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization rate per boe
|
|
$
|
12.10
|
|
|
$
|
7.58
|
|
|
$
|
8.86
|
|
|
$
|
12.61
|
|
|
$
|
11.40
|
|
|
$
|
8.62
|
|
|
$
|
|
|
|
$
|
10.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues
|
|
$
|
5,083
|
|
|
$
|
1,651
|
|
|
$
|
2,739
|
|
|
$
|
372
|
|
|
$
|
2,103
|
|
|
$
|
380
|
|
|
$
|
|
|
|
$
|
12,328
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring(1)
|
|
|
1,081
|
|
|
|
410
|
|
|
|
398
|
|
|
|
133
|
|
|
|
261
|
|
|
|
188
|
|
|
|
|
|
|
|
2,471
|
|
Additional
|
|
|
2,667
|
|
|
|
1,689
|
|
|
|
|
|
|
|
|
|
|
|
569
|
|
|
|
409
|
|
|
|
|
|
|
|
5,334
|
|
Asset retirement obligation accretion
|
|
|
66
|
|
|
|
14
|
|
|
|
|
|
|
|
6
|
|
|
|
13
|
|
|
|
2
|
|
|
|
|
|
|
|
101
|
|
Lease operating expenses
|
|
|
926
|
|
|
|
337
|
|
|
|
241
|
|
|
|
104
|
|
|
|
191
|
|
|
|
111
|
|
|
|
|
|
|
|
1,910
|
|
Gathering and transportation
|
|
|
40
|
|
|
|
63
|
|
|
|
21
|
|
|
|
|
|
|
|
28
|
|
|
|
5
|
|
|
|
|
|
|
|
157
|
|
Production taxes(2)
|
|
|
201
|
|
|
|
34
|
|
|
|
|
|
|
|
11
|
|
|
|
695
|
|
|
|
|
|
|
|
|
|
|
|
941
|
|
Income tax
|
|
|
37
|
|
|
|
(215
|
)
|
|
|
998
|
|
|
|
35
|
|
|
|
173
|
|
|
|
(118
|
)
|
|
|
|
|
|
|
910
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,018
|
|
|
|
2,332
|
|
|
|
1,658
|
|
|
|
289
|
|
|
|
1,930
|
|
|
|
597
|
|
|
|
|
|
|
|
11,824
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
65
|
|
|
$
|
(681
|
)
|
|
$
|
1,081
|
|
|
$
|
83
|
|
|
$
|
173
|
|
|
$
|
(217
|
)
|
|
$
|
|
|
|
$
|
504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization rate per boe
|
|
$
|
14.08
|
|
|
$
|
13.11
|
|
|
$
|
8.48
|
|
|
$
|
11.26
|
|
|
$
|
11.89
|
|
|
$
|
10.49
|
|
|
$
|
|
|
|
$
|
12.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
This amount only reflects DD&A of capitalized costs of oil
and gas proved properties and, therefore, does not agree with
DD&A reflected on Note 11 Business Segment
Information. |
|
(2) |
|
This amount only reflects amounts directly related to oil and
gas producing properties and, therefore, does not agree with
taxes other than income reflected on Note 11
Business Segment Information. |
F-53
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Costs
Incurred in Oil and Gas Property Acquisitions, Exploration, and
Development Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Egypt
|
|
|
Australia
|
|
|
North Sea
|
|
|
Argentina
|
|
|
International
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
5,604
|
|
|
$
|
2,752
|
|
|
$
|
325
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
8,681
|
|
Unproved
|
|
|
2,497
|
|
|
|
542
|
|
|
|
145
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,216
|
|
Exploration
|
|
|
261
|
|
|
|
312
|
|
|
|
477
|
|
|
|
236
|
|
|
|
142
|
|
|
|
136
|
|
|
|
20
|
|
|
|
1,584
|
|
Development
|
|
|
1,724
|
|
|
|
611
|
|
|
|
290
|
|
|
|
496
|
|
|
|
475
|
|
|
|
131
|
|
|
|
|
|
|
|
3,727
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred(1)
|
|
$
|
10,086
|
|
|
$
|
4,217
|
|
|
$
|
1,237
|
|
|
$
|
764
|
|
|
$
|
617
|
|
|
$
|
267
|
|
|
$
|
20
|
|
|
$
|
17,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes capitalized interest and asset retirement costs as
follows:
|
Capitalized interest
|
|
$
|
52
|
|
|
$
|
23
|
|
|
$
|
10
|
|
|
$
|
15
|
|
|
$
|
|
|
|
$
|
11
|
|
|
$
|
|
|
|
$
|
111
|
|
Asset retirement costs
|
|
|
1,099
|
|
|
|
98
|
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
16
|
|
|
|
|
|
|
|
1,306
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
196
|
|
|
$
|
13
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
24
|
|
|
$
|
|
|
|
$
|
233
|
|
Unproved
|
|
|
|
|
|
|
|
|
|
|
39
|
|
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
77
|
|
Exploration
|
|
|
233
|
|
|
|
179
|
|
|
|
438
|
|
|
|
182
|
|
|
|
105
|
|
|
|
97
|
|
|
|
11
|
|
|
|
1,245
|
|
Development
|
|
|
892
|
|
|
|
326
|
|
|
|
245
|
|
|
|
474
|
|
|
|
270
|
|
|
|
47
|
|
|
|
|
|
|
|
2,254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred(1)
|
|
$
|
1,321
|
|
|
$
|
518
|
|
|
$
|
722
|
|
|
$
|
694
|
|
|
$
|
375
|
|
|
$
|
168
|
|
|
$
|
11
|
|
|
$
|
3,809
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes capitalized interest and asset retirement costs as
follows:
|
Capitalized interest
|
|
$
|
15
|
|
|
$
|
12
|
|
|
$
|
8
|
|
|
$
|
15
|
|
|
$
|
|
|
|
$
|
11
|
|
|
$
|
|
|
|
$
|
61
|
|
Asset retirement costs
|
|
|
182
|
|
|
|
80
|
|
|
|
|
|
|
|
38
|
|
|
|
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
293
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
70
|
|
|
$
|
5
|
|
|
$
|
|
|
|
$
|
(1
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
74
|
|
Unproved
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75
|
|
Exploration
|
|
|
382
|
|
|
|
254
|
|
|
|
193
|
|
|
|
293
|
|
|
|
107
|
|
|
|
256
|
|
|
|
28
|
|
|
|
1,513
|
|
Development
|
|
|
2,201
|
|
|
|
580
|
|
|
|
668
|
|
|
|
589
|
|
|
|
364
|
|
|
|
98
|
|
|
|
|
|
|
|
4,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred(1)
|
|
$
|
2,728
|
|
|
$
|
839
|
|
|
$
|
861
|
|
|
$
|
881
|
|
|
$
|
471
|
|
|
$
|
354
|
|
|
$
|
28
|
|
|
$
|
6,162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes capitalized interest and asset retirement costs as
follows:
|
Capitalized interest
|
|
$
|
20
|
|
|
$
|
12
|
|
|
$
|
8
|
|
|
$
|
9
|
|
|
$
|
1
|
|
|
$
|
24
|
|
|
$
|
|
|
|
$
|
74
|
|
Asset retirement costs
|
|
|
379
|
|
|
|
117
|
|
|
|
|
|
|
|
(7
|
)
|
|
|
12
|
|
|
|
13
|
|
|
|
|
|
|
|
514
|
|
Capitalized
Costs
The following table sets forth the capitalized costs and
associated accumulated depreciation, depletion and amortization,
including impairments, relating to the Companys oil and
gas production, exploration and development activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Egypt
|
|
|
Australia
|
|
|
North Sea
|
|
|
Argentina
|
|
|
International
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
30,273
|
|
|
$
|
11,679
|
|
|
$
|
5,286
|
|
|
$
|
4,435
|
|
|
$
|
4,078
|
|
|
$
|
2,153
|
|
|
$
|
|
|
|
$
|
57,904
|
|
Unproved properties
|
|
|
2,791
|
|
|
|
1,113
|
|
|
|
542
|
|
|
|
254
|
|
|
|
31
|
|
|
|
259
|
|
|
|
58
|
|
|
|
5,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,064
|
|
|
|
12,792
|
|
|
|
5,828
|
|
|
|
4,689
|
|
|
|
4,109
|
|
|
|
2,412
|
|
|
|
58
|
|
|
|
62,952
|
|
Accumulated DD&A
|
|
|
(14,391
|
)
|
|
|
(6,027
|
)
|
|
|
(2,971
|
)
|
|
|
(1,642
|
)
|
|
|
(2,146
|
)
|
|
|
(1,153
|
)
|
|
|
|
|
|
|
(28,330
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
18,673
|
|
|
$
|
6,765
|
|
|
$
|
2,857
|
|
|
$
|
3,047
|
|
|
$
|
1,963
|
|
|
$
|
1,259
|
|
|
$
|
58
|
|
|
$
|
34,622
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
22,777
|
|
|
$
|
8,172
|
|
|
$
|
4,271
|
|
|
$
|
3,661
|
|
|
$
|
3,477
|
|
|
$
|
1,909
|
|
|
$
|
|
|
|
$
|
44,267
|
|
Unproved properties
|
|
|
201
|
|
|
|
405
|
|
|
|
320
|
|
|
|
265
|
|
|
|
14
|
|
|
|
236
|
|
|
|
38
|
|
|
|
1,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,978
|
|
|
|
8,577
|
|
|
|
4,591
|
|
|
|
3,926
|
|
|
|
3,491
|
|
|
|
2,145
|
|
|
|
38
|
|
|
|
45,746
|
|
Accumulated DD&A
|
|
|
(13,270
|
)
|
|
|
(5,780
|
)
|
|
|
(2,319
|
)
|
|
|
(1,256
|
)
|
|
|
(1,844
|
)
|
|
|
(1,000
|
)
|
|
|
|
|
|
|
(25,469
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
9,708
|
|
|
$
|
2,797
|
|
|
$
|
2,272
|
|
|
$
|
2,670
|
|
|
$
|
1,647
|
|
|
$
|
1,145
|
|
|
$
|
38
|
|
|
$
|
20,277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-54
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Costs
Not Being Amortized
The following table sets forth a summary of oil and gas property
costs not being amortized at December 31, 2010, by the year
in which such costs were incurred. There are no individually
significant properties or significant development projects
included in costs not being amortized. The majority of the
evaluation activities are expected to be completed within five
to ten years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
Total
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
and Prior
|
|
|
|
(In millions)
|
|
|
Property acquisition costs
|
|
$
|
4,118
|
|
|
$
|
3,491
|
|
|
$
|
108
|
|
|
$
|
187
|
|
|
$
|
332
|
|
Exploration and development
|
|
|
802
|
|
|
|
481
|
|
|
|
207
|
|
|
|
40
|
|
|
|
74
|
|
Capitalized interest
|
|
|
128
|
|
|
|
52
|
|
|
|
18
|
|
|
|
30
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,048
|
|
|
$
|
4,024
|
|
|
$
|
333
|
|
|
$
|
257
|
|
|
$
|
434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and Gas Reserve Information
Effective December 31, 2009, Apache adopted revised oil and
gas disclosure requirements set forth by the SEC in Release
No. 33-8995,
Modernization of Oil and Gas Reporting and as
codified by the FASB in ASC Topic 932, Extractive
Industries Oil and Gas. The new rules include
changes to the pricing used to estimate reserves, the option to
disclose probable and possible reserves, revised definitions for
proved reserves, additional disclosures with respect to
undeveloped reserves, and other new or revised definitions and
disclosures.
F-55
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
There are numerous uncertainties inherent in estimating
quantities of proved reserves and projecting future rates of
production and timing of development expenditures. The following
reserve data only represent estimates and should not be
construed as being exact.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Crude Oil, Condensate and Natural Gas Liquids
|
|
|
Natural Gas
|
|
|
(Thousands
|
|
|
|
(Thousands of barrels)
|
|
|
(Millions of cubic feet)
|
|
|
barrels
|
|
|
|
United
|
|
|
|
|
|
|
|
|
|
|
|
North
|
|
|
|
|
|
|
|
|
United
|
|
|
|
|
|
|
|
|
|
|
|
North
|
|
|
|
|
|
|
|
|
of oil
|
|
|
|
States
|
|
|
Canada
|
|
|
Egypt
|
|
|
Australia
|
|
|
Sea
|
|
|
Argentina
|
|
|
Total
|
|
|
States
|
|
|
Canada
|
|
|
Egypt
|
|
|
Australia
|
|
|
Sea
|
|
|
Argentina
|
|
|
Total
|
|
|
equivalent)
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
394,960
|
|
|
|
94,090
|
|
|
|
74,315
|
|
|
|
19,948
|
|
|
|
186,706
|
|
|
|
24,535
|
|
|
|
794,554
|
|
|
|
1,923,750
|
|
|
|
1,605,675
|
|
|
|
818,509
|
|
|
|
536,131
|
|
|
|
6,304
|
|
|
|
442,058
|
|
|
|
5,332,427
|
|
|
|
1,683,292
|
|
December 31, 2008
|
|
|
363,516
|
|
|
|
85,038
|
|
|
|
93,103
|
|
|
|
39,758
|
|
|
|
168,925
|
|
|
|
26,752
|
|
|
|
777,092
|
|
|
|
1,866,988
|
|
|
|
1,594,782
|
|
|
|
1,010,102
|
|
|
|
713,290
|
|
|
|
5,585
|
|
|
|
487,980
|
|
|
|
5,678,727
|
|
|
|
1,723,547
|
|
December 31, 2009
|
|
|
373,010
|
|
|
|
89,222
|
|
|
|
97,787
|
|
|
|
34,662
|
|
|
|
142,022
|
|
|
|
25,985
|
|
|
|
762,688
|
|
|
|
1,785,155
|
|
|
|
1,436,151
|
|
|
|
838,000
|
|
|
|
699,963
|
|
|
|
4,851
|
|
|
|
473,145
|
|
|
|
5,237,265
|
|
|
|
1,635,565
|
|
December 31, 2010
|
|
|
514,537
|
|
|
|
113,993
|
|
|
|
109,657
|
|
|
|
48,072
|
|
|
|
115,705
|
|
|
|
22,458
|
|
|
|
924,422
|
|
|
|
2,284,116
|
|
|
|
2,181,615
|
|
|
|
748,573
|
|
|
|
682,763
|
|
|
|
4,144
|
|
|
|
462,206
|
|
|
|
6,363,417
|
|
|
|
1,984,991
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
156,655
|
|
|
|
83,866
|
|
|
|
20,292
|
|
|
|
56,780
|
|
|
|
18,011
|
|
|
|
3,552
|
|
|
|
339,156
|
|
|
|
775,298
|
|
|
|
727,853
|
|
|
|
364,374
|
|
|
|
611,363
|
|
|
|
|
|
|
|
61,402
|
|
|
|
2,540,290
|
|
|
|
762,538
|
|
December 31, 2008
|
|
|
151,248
|
|
|
|
70,707
|
|
|
|
21,303
|
|
|
|
36,777
|
|
|
|
18,990
|
|
|
|
5,027
|
|
|
|
304,052
|
|
|
|
670,194
|
|
|
|
608,580
|
|
|
|
360,876
|
|
|
|
540,255
|
|
|
|
|
|
|
|
58,393
|
|
|
|
2,238,298
|
|
|
|
677,102
|
|
December 31, 2009
|
|
|
150,627
|
|
|
|
57,552
|
|
|
|
17,806
|
|
|
|
43,779
|
|
|
|
29,692
|
|
|
|
5,104
|
|
|
|
304,560
|
|
|
|
652,766
|
|
|
|
869,197
|
|
|
|
321,141
|
|
|
|
661,478
|
|
|
|
|
|
|
|
54,184
|
|
|
|
2,558,766
|
|
|
|
731,021
|
|
December 31, 2010
|
|
|
244,478
|
|
|
|
60,997
|
|
|
|
17,470
|
|
|
|
18,064
|
|
|
|
38,663
|
|
|
|
4,641
|
|
|
|
384,313
|
|
|
|
988,869
|
|
|
|
1,310,352
|
|
|
|
328,344
|
|
|
|
805,735
|
|
|
|
|
|
|
|
70,465
|
|
|
|
3,503,765
|
|
|
|
968,274
|
|
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007
|
|
|
551,615
|
|
|
|
177,955
|
|
|
|
94,608
|
|
|
|
76,729
|
|
|
|
204,717
|
|
|
|
28,086
|
|
|
|
1,133,710
|
|
|
|
2,699,048
|
|
|
|
2,333,528
|
|
|
|
1,182,883
|
|
|
|
1,147,494
|
|
|
|
6,304
|
|
|
|
503,460
|
|
|
|
7,872,717
|
|
|
|
2,445,829
|
|
Extensions, discoveries and other additions
|
|
|
38,010
|
|
|
|
5,623
|
|
|
|
28,966
|
|
|
|
4,401
|
|
|
|
9,288
|
|
|
|
9,261
|
|
|
|
95,549
|
|
|
|
247,100
|
|
|
|
192,974
|
|
|
|
109,488
|
|
|
|
151,308
|
|
|
|
362
|
|
|
|
114,852
|
|
|
|
816,084
|
|
|
|
231,563
|
|
Purchases of minerals in-place
|
|
|
1,919
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,926
|
|
|
|
27,551
|
|
|
|
1,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,308
|
|
|
|
6,810
|
|
Revisions of previous estimates
|
|
|
(31,540
|
)
|
|
|
(18,787
|
)
|
|
|
15,264
|
|
|
|
(1,576
|
)
|
|
|
(4,315
|
)
|
|
|
30
|
|
|
|
(40,924
|
)
|
|
|
(175,834
|
)
|
|
|
(134,563
|
)
|
|
|
175,125
|
|
|
|
(238
|
)
|
|
|
(116
|
)
|
|
|
(330
|
)
|
|
|
(135,956
|
)
|
|
|
(63,583
|
)
|
Production
|
|
|
(35,057
|
)
|
|
|
(7,038
|
)
|
|
|
(24,432
|
)
|
|
|
(3,019
|
)
|
|
|
(21,775
|
)
|
|
|
(5,598
|
)
|
|
|
(96,919
|
)
|
|
|
(248,835
|
)
|
|
|
(129,100
|
)
|
|
|
(96,518
|
)
|
|
|
(45,019
|
)
|
|
|
(965
|
)
|
|
|
(71,608
|
)
|
|
|
(592,045
|
)
|
|
|
(195,593
|
)
|
Sales of properties
|
|
|
(10,183
|
)
|
|
|
(2,015
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,198
|
)
|
|
|
(11,848
|
)
|
|
|
(61,235
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(73,083
|
)
|
|
|
(24,378
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008
|
|
|
514,764
|
|
|
|
155,745
|
|
|
|
114,406
|
|
|
|
76,535
|
|
|
|
187,915
|
|
|
|
31,779
|
|
|
|
1,081,144
|
|
|
|
2,537,182
|
|
|
|
2,203,361
|
|
|
|
1,370,978
|
|
|
|
1,253,545
|
|
|
|
5,585
|
|
|
|
546,374
|
|
|
|
7,917,025
|
|
|
|
2,400,648
|
|
Extensions, discoveries and other additions
|
|
|
17,642
|
|
|
|
1,839
|
|
|
|
41,104
|
|
|
|
3,574
|
|
|
|
6,056
|
|
|
|
4,865
|
|
|
|
75,080
|
|
|
|
150,668
|
|
|
|
340,278
|
|
|
|
2,142
|
|
|
|
174,883
|
|
|
|
252
|
|
|
|
50,714
|
|
|
|
718,937
|
|
|
|
194,903
|
|
Purchases of minerals in-place
|
|
|
13,023
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,023
|
|
|
|
47,782
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47,817
|
|
|
|
20,993
|
|
Revisions of previous estimates
|
|
|
12,981
|
|
|
|
(4,504
|
)
|
|
|
(6,286
|
)
|
|
|
1,901
|
|
|
|
2
|
|
|
|
(173
|
)
|
|
|
3,921
|
|
|
|
(54,591
|
)
|
|
|
(107,205
|
)
|
|
|
(81,623
|
)
|
|
|
33
|
|
|
|
|
|
|
|
(2,395
|
)
|
|
|
(245,781
|
)
|
|
|
(37,043
|
)
|
Production
|
|
|
(34,773
|
)
|
|
|
(6,306
|
)
|
|
|
(33,631
|
)
|
|
|
(3,569
|
)
|
|
|
(22,259
|
)
|
|
|
(5,382
|
)
|
|
|
(105,920
|
)
|
|
|
(243,120
|
)
|
|
|
(131,121
|
)
|
|
|
(132,356
|
)
|
|
|
(67,020
|
)
|
|
|
(986
|
)
|
|
|
(67,364
|
)
|
|
|
(641,967
|
)
|
|
|
(212,915
|
)
|
Sales of properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2009
|
|
|
523,637
|
|
|
|
146,774
|
|
|
|
115,593
|
|
|
|
78,441
|
|
|
|
171,714
|
|
|
|
31,089
|
|
|
|
1,067,248
|
|
|
|
2,437,921
|
|
|
|
2,305,348
|
|
|
|
1,159,141
|
|
|
|
1,361,441
|
|
|
|
4,851
|
|
|
|
527,329
|
|
|
|
7,796,031
|
|
|
|
2,366,586
|
|
Extensions, discoveries and other additions
|
|
|
72,928
|
|
|
|
6,816
|
|
|
|
41,205
|
|
|
|
4,452
|
|
|
|
3,383
|
|
|
|
426
|
|
|
|
129,210
|
|
|
|
102,180
|
|
|
|
274,755
|
|
|
|
46,692
|
|
|
|
199,958
|
|
|
|
166
|
|
|
|
71,632
|
|
|
|
695,383
|
|
|
|
245,108
|
|
Purchases of minerals in-place
|
|
|
195,131
|
|
|
|
42,440
|
|
|
|
11,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
248,832
|
|
|
|
951,654
|
|
|
|
1,064,618
|
|
|
|
49,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,065,316
|
|
|
|
593,051
|
|
Revisions of previous estimates
|
|
|
7,597
|
|
|
|
(14,592
|
)
|
|
|
(4,723
|
)
|
|
|
|
|
|
|
|
|
|
|
379
|
|
|
|
(11,339
|
)
|
|
|
47,989
|
|
|
|
(8,211
|
)
|
|
|
(41,137
|
)
|
|
|
|
|
|
|
|
|
|
|
1,173
|
|
|
|
(186
|
)
|
|
|
(11,370
|
)
|
Production
|
|
|
(40,278
|
)
|
|
|
(6,375
|
)
|
|
|
(36,209
|
)
|
|
|
(16,757
|
)
|
|
|
(20,729
|
)
|
|
|
(4,795
|
)
|
|
|
(125,143
|
)
|
|
|
(266,759
|
)
|
|
|
(144,542
|
)
|
|
|
(136,823
|
)
|
|
|
(72,901
|
)
|
|
|
(873
|
)
|
|
|
(67,463
|
)
|
|
|
(689,361
|
)
|
|
|
(240,037
|
)
|
Sales of properties
|
|
|
|
|
|
|
(73
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(73
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
(73
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2010
|
|
|
759,015
|
|
|
|
174,990
|
|
|
|
127,127
|
|
|
|
66,136
|
|
|
|
154,368
|
|
|
|
27,099
|
|
|
|
1,308,735
|
|
|
|
3,272,985
|
|
|
|
3,491,967
|
|
|
|
1,076,917
|
|
|
|
1,488,498
|
|
|
|
4,144
|
|
|
|
532,671
|
|
|
|
9,867,182
|
|
|
|
2,953,265
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximately 17 percent of Apaches year-end 2010
estimated proved developed reserves are classified as proved not
producing. These reserves relate to zones that are either behind
pipe, or that have been completed but not yet produced, or zones
that have been produced in the past, but are not now producing
because of mechanical reasons. These reserves are considered to
be a lower tier of reserves than producing reserves because they
are frequently based on volumetric calculations rather than
performance data. Future production associated with behind pipe
reserves is scheduled to follow depletion of the currently
producing zones in the same wellbores. It should be noted that
additional capital may have to be spent to access these
reserves. The capital and economic impact of production timing
are reflected in this Note 12, under Future Net Cash
Flows.
F-56
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Future
Net Cash Flows
Future cash inflows as of December 31, 2010 and 2009 were
calculated using an unweighted arithmetic average of oil and gas
prices in effect on the first day of each month in the
respective year, except where prices are defined by contractual
arrangements. Future cash inflows as of December 31, 2008
were estimated using oil and gas prices in effect at the end of
the year, except where prices are defined by contractual
arrangements, in accordance with SEC guidance in effect prior to
the issuance of the Modernization Rules. Operating costs,
production and ad valorem taxes and future development costs are
based on current costs with no escalation.
The following table sets forth unaudited information concerning
future net cash flows for proved oil and gas reserves, net of
income tax expense. Income tax expense has been computed using
expected future tax rates and giving effect to tax deductions
and credits available, under current laws, and which relate to
oil and gas producing activities. This information does not
purport to present the fair market value of the Companys
oil and gas assets, but does present a standardized disclosure
concerning possible future net cash flows that would result
under the assumptions used.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
States
|
|
|
Canada
|
|
|
Egypt
|
|
|
Australia
|
|
|
North Sea
|
|
|
Argentina
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash inflows
|
|
$
|
70,119
|
|
|
$
|
27,738
|
|
|
$
|
13,086
|
|
|
$
|
12,787
|
|
|
$
|
11,697
|
|
|
$
|
2,627
|
|
|
$
|
138,054
|
|
Production costs
|
|
|
(20,122
|
)
|
|
|
(12,207
|
)
|
|
|
(1,432
|
)
|
|
|
(2,808
|
)
|
|
|
(5,974
|
)
|
|
|
(968
|
)
|
|
|
(43,511
|
)
|
Development costs
|
|
|
(5,695
|
)
|
|
|
(2,736
|
)
|
|
|
(2,035
|
)
|
|
|
(2,288
|
)
|
|
|
(1,289
|
)
|
|
|
(182
|
)
|
|
|
(14,225
|
)
|
Income tax expense
|
|
|
(11,635
|
)
|
|
|
(1,464
|
)
|
|
|
(3,407
|
)
|
|
|
(2,213
|
)
|
|
|
(2,207
|
)
|
|
|
(177
|
)
|
|
|
(21,103
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows
|
|
|
32,667
|
|
|
|
11,331
|
|
|
|
6,212
|
|
|
|
5,478
|
|
|
|
2,227
|
|
|
|
1,300
|
|
|
|
59,215
|
|
10 percent discount rate
|
|
|
(17,289
|
)
|
|
|
(5,446
|
)
|
|
|
(1,744
|
)
|
|
|
(3,407
|
)
|
|
|
(532
|
)
|
|
|
(355
|
)
|
|
|
(28,773
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted future net cash flows(1)
|
|
$
|
15,378
|
|
|
$
|
5,885
|
|
|
$
|
4,468
|
|
|
$
|
2,071
|
|
|
$
|
1,695
|
|
|
$
|
945
|
|
|
$
|
30,442
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash inflows
|
|
$
|
38,591
|
|
|
$
|
15,698
|
|
|
$
|
10,176
|
|
|
$
|
11,096
|
|
|
$
|
6,871
|
|
|
$
|
2,434
|
|
|
$
|
84,866
|
|
Production costs
|
|
|
(12,399
|
)
|
|
|
(7,315
|
)
|
|
|
(1,330
|
)
|
|
|
(2,537
|
)
|
|
|
(4,215
|
)
|
|
|
(860
|
)
|
|
|
(28,656
|
)
|
Development costs
|
|
|
(3,177
|
)
|
|
|
(1,790
|
)
|
|
|
(1,512
|
)
|
|
|
(1,949
|
)
|
|
|
(780
|
)
|
|
|
(163
|
)
|
|
|
(9,371
|
)
|
Income tax expense
|
|
|
(6,433
|
)
|
|
|
(1,010
|
)
|
|
|
(2,527
|
)
|
|
|
(1,852
|
)
|
|
|
(918
|
)
|
|
|
(351
|
)
|
|
|
(13,091
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows
|
|
|
16,582
|
|
|
|
5,583
|
|
|
|
4,807
|
|
|
|
4,758
|
|
|
|
958
|
|
|
|
1,060
|
|
|
|
33,748
|
|
10 percent discount rate
|
|
|
(8,555
|
)
|
|
|
(2,974
|
)
|
|
|
(1,365
|
)
|
|
|
(2,692
|
)
|
|
|
(70
|
)
|
|
|
(341
|
)
|
|
|
(15,997
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted future net cash flows(1)
|
|
$
|
8,027
|
|
|
$
|
2,609
|
|
|
$
|
3,442
|
|
|
$
|
2,066
|
|
|
$
|
888
|
|
|
$
|
719
|
|
|
$
|
17,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Estimated future net cash flows before income tax expense,
discounted at 10 percent per annum, totaled approximately
$41.0 billion and $24.4 billion as of
December 31, 2010 and 2009, respectively. |
F-57
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table sets forth the principal sources of change
in the discounted future net cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Sales, net of production costs
|
|
$
|
(9,152
|
)
|
|
$
|
(5,943
|
)
|
|
$
|
(9,725
|
)
|
Net change in prices and production costs
|
|
|
13,006
|
|
|
|
7,650
|
|
|
|
(25,451
|
)
|
Discoveries and improved recovery, net of related costs
|
|
|
5,147
|
|
|
|
1,718
|
|
|
|
3,132
|
|
Change in future development costs
|
|
|
(1,637
|
)
|
|
|
(447
|
)
|
|
|
(144
|
)
|
Previously estimated development costs incurred during the period
|
|
|
1,355
|
|
|
|
1,685
|
|
|
|
1,480
|
|
Revision of quantities
|
|
|
(1,905
|
)
|
|
|
(1,258
|
)
|
|
|
215
|
|
Purchases of minerals in-place
|
|
|
7,794
|
|
|
|
530
|
|
|
|
1,675
|
|
Accretion of discount
|
|
|
2,439
|
|
|
|
1,054
|
|
|
|
4,693
|
|
Change in income taxes
|
|
|
(4,535
|
)
|
|
|
823
|
|
|
|
7,821
|
|
Sales of properties
|
|
|
(3
|
)
|
|
|
|
|
|
|
(654
|
)
|
Change in production rates and other
|
|
|
182
|
|
|
|
(1,009
|
)
|
|
|
(842
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
12,691
|
|
|
$
|
4,803
|
|
|
$
|
(17,800
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13.
|
SUPPLEMENTAL
QUARTERLY FINANCIAL DATA (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Total
|
|
|
|
(In millions, except per share amounts)
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other
|
|
$
|
2,673
|
|
|
$
|
2,972
|
|
|
$
|
3,013
|
|
|
$
|
3,434
|
|
|
$
|
12,092
|
|
Expenses
|
|
|
1,968
|
|
|
|
2,112
|
|
|
|
2,235
|
|
|
|
2,745
|
|
|
|
9,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
705
|
|
|
$
|
860
|
|
|
$
|
778
|
|
|
$
|
689
|
|
|
$
|
3,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income attributable to common stock
|
|
$
|
705
|
|
|
$
|
860
|
|
|
$
|
765
|
|
|
$
|
670
|
|
|
$
|
3,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
2.09
|
|
|
$
|
2.55
|
|
|
$
|
2.14
|
|
|
$
|
1.79
|
|
|
$
|
8.53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
2.08
|
|
|
$
|
2.53
|
|
|
$
|
2.12
|
|
|
$
|
1.77
|
|
|
$
|
8.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other
|
|
$
|
1,634
|
|
|
$
|
2,093
|
|
|
$
|
2,333
|
|
|
$
|
2,555
|
|
|
$
|
8,615
|
|
Expenses
|
|
|
3,391
|
|
|
|
1,648
|
|
|
|
1,891
|
|
|
|
1,970
|
|
|
|
8,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(1,757
|
)
|
|
$
|
445
|
|
|
$
|
442
|
|
|
$
|
585
|
|
|
$
|
(285
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) attributable to common stock
|
|
$
|
(1,758
|
)
|
|
$
|
443
|
|
|
$
|
441
|
|
|
$
|
582
|
|
|
$
|
(292
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(5.25
|
)
|
|
$
|
1.32
|
|
|
$
|
1.31
|
|
|
$
|
1.73
|
|
|
$
|
(.87
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
(5.25
|
)
|
|
$
|
1.31
|
|
|
$
|
1.30
|
|
|
$
|
1.72
|
|
|
$
|
(.87
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The sum of the individual quarterly net income (loss) per common
share amounts may not agree with
year-to-date
net income per common share as each quarterly computation is
based on the weighted-average number of common shares
outstanding during that period. Potentially dilutive securities
were included in the computation of diluted net income per
common share for each quarter in which the Company reported net
income. Securities deemed anti-dilutive were excluded from each
quarter in which the Company reported a net loss. |
F-58
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
14.
|
SUPPLEMENTAL
GUARANTOR INFORMATION
|
Rule 3-10
of SEC
Regulation S-X
(Rule 3-10)
generally requires filing of financial statements by every
issuer of a registered security with independent operations.
Rule 3-10
also allows condensed consolidating financial statements in a
footnote of the parent company financial statements as an
alternative to filing separate financial statements, if the
publicly-traded notes are fully and unconditionally guaranteed
by the parent company. Issuers with no independent operations
qualify as finance subsidiaries and are exempt from
the reporting requirements. Apache Finance Canada does not
qualify as a finance subsidiary, neither did Apache
Finance Australia when it had registered securities during the
periods presented.
Each of the companies presented in the condensed consolidating
financial statements is wholly owned and has been consolidated
in Apache Corporations consolidated financial statements
for all applicable periods presented. As such, the condensed
consolidating financial statements should be read in conjunction
with the financial statements of Apache Corporation and
subsidiaries and notes thereto of which this note is an integral
part.
Apache
Finance Australia
Apache Finance Australia issued approximately $270 million
of publicly-traded notes that were fully and unconditionally
guaranteed by Apache Corporation and Apache North America, Inc.
during the relevant periods presented. In 2007,
$170 million of these notes matured and were repaid. The
remaining $100 million of publicly-traded notes matured on
March 15, 2009, and were repaid using existing cash
balances.
Apache
Finance Canada
Apache Finance Canada issued approximately $300 million of
publicly-traded notes due in 2029 and an additional
$350 million of publicly-traded notes due in 2015 that are
fully and unconditionally guaranteed by Apache.
Apache
Deepwater
Apache Deepwater assumed publicly traded debt upon consummation
of its merger with Mariner. Mariners publicly traded debt
included $300 million of 7.5-percent senior notes due 2013,
$300 million of 11.75-percent senior notes due 2016, and
$300 million of 8-percent senior notes due 2017. On
December 13, 2010, Apache Deepwater redeemed the
7.5-percent notes, the 8-percent notes, and 35 percent of
the 11.75-percent notes pursuant to the provisions of each
notes indenture. On December 14, 2010, Apache
Deepwater redeemed the remaining 65 percent of the
11.75-percent notes.
F-59
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
CONDENSED
CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
Apache
|
|
|
Apache
|
|
|
of Apache
|
|
|
Reclassifications
|
|
|
|
|
|
|
Corporation
|
|
|
Finance Canada
|
|
|
Corporation
|
|
|
& Eliminations
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
|
REVENUES AND OTHER:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues
|
|
$
|
3,665
|
|
|
$
|
|
|
|
$
|
8,518
|
|
|
$
|
|
|
|
$
|
12,183
|
|
Equity in net income (loss) of affiliates
|
|
|
2,265
|
|
|
|
81
|
|
|
|
(7
|
)
|
|
|
(2,339
|
)
|
|
|
|
|
Other
|
|
|
27
|
|
|
|
(1
|
)
|
|
|
(113
|
)
|
|
|
(4
|
)
|
|
|
(91
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,957
|
|
|
|
80
|
|
|
|
8,398
|
|
|
|
(2,343
|
)
|
|
|
12,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
1,041
|
|
|
|
|
|
|
|
2,042
|
|
|
|
|
|
|
|
3,083
|
|
Asset retirement obligation accretion
|
|
|
57
|
|
|
|
|
|
|
|
54
|
|
|
|
|
|
|
|
111
|
|
Lease operating expenses
|
|
|
797
|
|
|
|
|
|
|
|
1,235
|
|
|
|
|
|
|
|
2,032
|
|
Gathering and transportation
|
|
|
42
|
|
|
|
|
|
|
|
136
|
|
|
|
|
|
|
|
178
|
|
Taxes other than income
|
|
|
140
|
|
|
|
|
|
|
|
550
|
|
|
|
|
|
|
|
690
|
|
General and administrative
|
|
|
273
|
|
|
|
|
|
|
|
111
|
|
|
|
(4
|
)
|
|
|
380
|
|
Merger, acquisitions & transition
|
|
|
183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
183
|
|
Financing costs, net
|
|
|
158
|
|
|
|
(19
|
)
|
|
|
90
|
|
|
|
|
|
|
|
229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,691
|
|
|
|
(19
|
)
|
|
|
4,218
|
|
|
|
(4
|
)
|
|
|
6,886
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES
|
|
|
3,266
|
|
|
|
99
|
|
|
|
4,180
|
|
|
|
(2,339
|
)
|
|
|
5,206
|
|
Provision for income taxes
|
|
|
234
|
|
|
|
25
|
|
|
|
1,915
|
|
|
|
|
|
|
|
2,174
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
3,032
|
|
|
|
74
|
|
|
|
2,265
|
|
|
|
(2,339
|
)
|
|
|
3,032
|
|
Preferred stock dividends
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME ATTRIBUTABLE TO COMMON STOCK
|
|
$
|
3,000
|
|
|
$
|
74
|
|
|
$
|
2,265
|
|
|
$
|
(2,339
|
)
|
|
$
|
3,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-60
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
CONDENSED
CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
Apache
|
|
|
Apache
|
|
|
of Apache
|
|
|
Reclassifications
|
|
|
|
|
|
|
Corporation
|
|
|
Finance Canada
|
|
|
Corporation
|
|
|
& Eliminations
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
|
REVENUES AND OTHER:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues
|
|
$
|
2,770
|
|
|
$
|
|
|
|
$
|
5,804
|
|
|
$
|
|
|
|
$
|
8,574
|
|
Equity in net income (loss) of affiliates
|
|
|
235
|
|
|
|
(448
|
)
|
|
|
168
|
|
|
|
45
|
|
|
|
|
|
Other
|
|
|
(3
|
)
|
|
|
59
|
|
|
|
(11
|
)
|
|
|
(4
|
)
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,002
|
|
|
|
(389
|
)
|
|
|
5,961
|
|
|
|
41
|
|
|
|
8,615
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
2,097
|
|
|
|
|
|
|
|
3,116
|
|
|
|
|
|
|
|
5,213
|
|
Asset retirement obligation accretion
|
|
|
63
|
|
|
|
|
|
|
|
42
|
|
|
|
|
|
|
|
105
|
|
Lease operating expenses
|
|
|
691
|
|
|
|
|
|
|
|
971
|
|
|
|
|
|
|
|
1,662
|
|
Gathering and transportation
|
|
|
34
|
|
|
|
|
|
|
|
109
|
|
|
|
|
|
|
|
143
|
|
Taxes other than income
|
|
|
100
|
|
|
|
|
|
|
|
480
|
|
|
|
|
|
|
|
580
|
|
General and administrative
|
|
|
275
|
|
|
|
|
|
|
|
73
|
|
|
|
(4
|
)
|
|
|
344
|
|
Financing costs, net
|
|
|
228
|
|
|
|
(15
|
)
|
|
|
29
|
|
|
|
|
|
|
|
242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,488
|
|
|
|
(15
|
)
|
|
|
4,820
|
|
|
|
(4
|
)
|
|
|
8,289
|
|
INCOME (LOSS) BEFORE INCOME TAXES
|
|
|
(486
|
)
|
|
|
(374
|
)
|
|
|
1,141
|
|
|
|
45
|
|
|
|
326
|
|
Provision (benefit) for income taxes
|
|
|
(201
|
)
|
|
|
(93
|
)
|
|
|
905
|
|
|
|
|
|
|
|
611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
(285
|
)
|
|
|
(281
|
)
|
|
|
236
|
|
|
|
45
|
|
|
|
(285
|
)
|
Preferred stock dividends
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME ATTRIBUTABLE TO COMMON STOCK
|
|
$
|
(292
|
)
|
|
$
|
(281
|
)
|
|
$
|
236
|
|
|
$
|
45
|
|
|
$
|
(292
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-61
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
CONDENSED
CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apache
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
Apache
|
|
|
Apache
|
|
|
Finance
|
|
|
Apache
|
|
|
of Apache
|
|
|
Reclassifications
|
|
|
|
|
|
|
Corporation
|
|
|
North America
|
|
|
Australia
|
|
|
Finance Canada
|
|
|
Corporation
|
|
|
& Eliminations
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
|
REVENUES AND OTHER:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues
|
|
$
|
4,552
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7,822
|
|
|
$
|
(46
|
)
|
|
$
|
12,328
|
|
Equity in net income (loss) of affiliates
|
|
|
526
|
|
|
|
71
|
|
|
|
68
|
|
|
|
(157
|
)
|
|
|
88
|
|
|
|
(596
|
)
|
|
|
|
|
Other
|
|
|
26
|
|
|
|
(30
|
)
|
|
|
30
|
|
|
|
59
|
|
|
|
(19
|
)
|
|
|
(4
|
)
|
|
|
62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,104
|
|
|
|
41
|
|
|
|
98
|
|
|
|
(98
|
)
|
|
|
7,891
|
|
|
|
(646
|
)
|
|
|
12,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
3,276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,574
|
|
|
|
|
|
|
|
7,850
|
|
Asset retirement obligation accretion
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
|
|
|
|
|
|
|
|
101
|
|
Lease operating expenses
|
|
|
821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,089
|
|
|
|
|
|
|
|
1,910
|
|
Gathering and transportation
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
164
|
|
|
|
(46
|
)
|
|
|
157
|
|
Taxes other than income
|
|
|
169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
816
|
|
|
|
|
|
|
|
985
|
|
General and administrative
|
|
|
223
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
69
|
|
|
|
(3
|
)
|
|
|
289
|
|
Financing costs, net
|
|
|
150
|
|
|
|
(11
|
)
|
|
|
18
|
|
|
|
(6
|
)
|
|
|
15
|
|
|
|
|
|
|
|
166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,744
|
|
|
|
(11
|
)
|
|
|
18
|
|
|
|
(6
|
)
|
|
|
6,762
|
|
|
|
(49
|
)
|
|
|
11,458
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) BEFORE INCOME TAXES
|
|
|
360
|
|
|
|
52
|
|
|
|
80
|
|
|
|
(92
|
)
|
|
|
1,129
|
|
|
|
(597
|
)
|
|
|
932
|
|
Provision (benefit) for income taxes
|
|
|
(353
|
)
|
|
|
(12
|
)
|
|
|
9
|
|
|
|
(28
|
)
|
|
|
604
|
|
|
|
|
|
|
|
220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
713
|
|
|
|
64
|
|
|
|
71
|
|
|
|
(64
|
)
|
|
|
525
|
|
|
|
(597
|
)
|
|
|
712
|
|
Preferred stock dividends
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME ATTRIBUTABLE TO COMMON STOCK
|
|
$
|
707
|
|
|
$
|
64
|
|
|
$
|
71
|
|
|
$
|
(64
|
)
|
|
$
|
525
|
|
|
$
|
(597
|
)
|
|
$
|
706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-62
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
CONDENSED
CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
Apache
|
|
|
Apache
|
|
|
of Apache
|
|
|
Reclassifications
|
|
|
|
|
|
|
Corporation
|
|
|
Finance Canada
|
|
|
Corporation
|
|
|
& Eliminations
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
|
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
|
|
$
|
(1,848
|
)
|
|
$
|
(100
|
)
|
|
$
|
8,674
|
|
|
$
|
|
|
|
$
|
6,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas property
|
|
|
(1,552
|
)
|
|
|
|
|
|
|
(2,855
|
)
|
|
|
|
|
|
|
(4,407
|
)
|
Additions to gathering, transmission and processing facilities
|
|
|
(4
|
)
|
|
|
|
|
|
|
(511
|
)
|
|
|
|
|
|
|
(515
|
)
|
Acquisitions of Devon properties
|
|
|
(1,018
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,018
|
)
|
Acquisitions of BP properties
|
|
|
|
|
|
|
|
|
|
|
(6,429
|
)
|
|
|
|
|
|
|
(6,429
|
)
|
Mariner Energy, Inc merger
|
|
|
|
|
|
|
|
|
|
|
(787
|
)
|
|
|
|
|
|
|
(787
|
)
|
Acquisitions, other
|
|
|
|
|
|
|
|
|
|
|
(126
|
)
|
|
|
|
|
|
|
(126
|
)
|
Short-term investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in and advances to subsidiaries, net
|
|
|
(2,853
|
)
|
|
|
|
|
|
|
|
|
|
|
2,853
|
|
|
|
|
|
Other, net
|
|
|
(72
|
)
|
|
|
|
|
|
|
(49
|
)
|
|
|
|
|
|
|
(121
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH USED IN INVESTING ACTIVITIES
|
|
|
(5,499
|
)
|
|
|
|
|
|
|
(10,757
|
)
|
|
|
2,853
|
|
|
|
(13,403
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commercial paper, credit facility and bank notes, net
|
|
|
928
|
|
|
|
|
|
|
|
(960
|
)
|
|
|
|
|
|
|
(32
|
)
|
Intercompany borrowings
|
|
|
|
|
|
|
2
|
|
|
|
2,720
|
|
|
|
(2,722
|
)
|
|
|
|
|
Fixed-rate debt borrowings
|
|
|
2,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,470
|
|
Payments on fixed-rate notes
|
|
|
|
|
|
|
|
|
|
|
(1,023
|
)
|
|
|
|
|
|
|
(1,023
|
)
|
Proceeds from issuance of common stock
|
|
|
2,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,258
|
|
Proceeds from issuance of mandatory convertible preferred stock
|
|
|
1,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,227
|
|
Dividends paid
|
|
|
(226
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(226
|
)
|
Common stock activity
|
|
|
70
|
|
|
|
96
|
|
|
|
35
|
|
|
|
(131
|
)
|
|
|
70
|
|
Redemption of preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
(21
|
)
|
|
|
|
|
|
|
40
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
|
|
6,706
|
|
|
|
98
|
|
|
|
812
|
|
|
|
(2,853
|
)
|
|
|
4,763
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE IN CASH AND CASH EQUIVALENTS
|
|
|
(641
|
)
|
|
|
(2
|
)
|
|
|
(1,271
|
)
|
|
|
|
|
|
|
(1,914
|
)
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
|
|
647
|
|
|
|
2
|
|
|
|
1,399
|
|
|
|
|
|
|
|
2,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
|
$
|
6
|
|
|
$
|
|
|
|
$
|
128
|
|
|
$
|
|
|
|
$
|
134
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-63
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
CONDENSED
CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
Apache
|
|
|
Apache
|
|
|
of Apache
|
|
|
Reclassifications
|
|
|
|
|
|
|
Corporation
|
|
|
Finance Canada
|
|
|
Corporation
|
|
|
& Eliminations
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
|
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
|
|
$
|
1,857
|
|
|
$
|
(15
|
)
|
|
$
|
2,382
|
|
|
$
|
|
|
|
$
|
4,224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas property
|
|
|
(1,008
|
)
|
|
|
|
|
|
|
(2,318
|
)
|
|
|
|
|
|
|
(3,326
|
)
|
Additions to gathering, transmission and processing facilities
|
|
|
|
|
|
|
|
|
|
|
(306
|
)
|
|
|
|
|
|
|
(306
|
)
|
Acquisitions, other
|
|
|
(196
|
)
|
|
|
|
|
|
|
(114
|
)
|
|
|
|
|
|
|
(310
|
)
|
Short-term investments
|
|
|
792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
792
|
|
Restricted cash
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Proceeds from sale of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
3
|
|
Investment in and advances to subsidiaries, net
|
|
|
(657
|
)
|
|
|
|
|
|
|
|
|
|
|
657
|
|
|
|
|
|
Other, net
|
|
|
(39
|
)
|
|
|
|
|
|
|
(75
|
)
|
|
|
|
|
|
|
(114
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH USED IN INVESTING ACTIVITIES
|
|
|
(1,093
|
)
|
|
|
|
|
|
|
(2,811
|
)
|
|
|
657
|
|
|
|
(3,247
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commercial paper, credit facility and bank notes, net
|
|
|
1
|
|
|
|
(3
|
)
|
|
|
903
|
|
|
|
(653
|
)
|
|
|
248
|
|
Fixed-rate debt borrowings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments on fixed-rate notes
|
|
|
|
|
|
|
|
|
|
|
(100
|
)
|
|
|
|
|
|
|
(100
|
)
|
Dividends paid
|
|
|
(209
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(209
|
)
|
Common stock activity
|
|
|
28
|
|
|
|
18
|
|
|
|
(14
|
)
|
|
|
(4
|
)
|
|
|
28
|
|
Redemption of preferred stock
|
|
|
(98
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(98
|
)
|
Other
|
|
|
20
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
|
|
(258
|
)
|
|
|
15
|
|
|
|
790
|
|
|
|
(657
|
)
|
|
|
(110
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE IN CASH AND CASH EQUIVALENTS
|
|
|
505
|
|
|
|
|
|
|
|
361
|
|
|
|
|
|
|
|
867
|
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
|
|
142
|
|
|
|
2
|
|
|
|
1,037
|
|
|
|
|
|
|
|
1,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
|
$
|
647
|
|
|
$
|
2
|
|
|
$
|
1,399
|
|
|
$
|
|
|
|
$
|
2,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-64
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
CONDENSED
CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
Apache
|
|
|
Apache
|
|
|
Apache
|
|
|
Apache
|
|
|
of Apache
|
|
|
Reclassifications
|
|
|
|
|
|
|
Corporation
|
|
|
North America
|
|
|
Finance Australia
|
|
|
Finance Canada
|
|
|
Corporation
|
|
|
& Eliminations
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
|
CASH PROVIDED BY (USED IN) OPERATING
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ACTIVITIES
|
|
$
|
1,590
|
|
|
$
|
(1
|
)
|
|
$
|
(12
|
)
|
|
$
|
3
|
|
|
$
|
5,485
|
|
|
$
|
|
|
|
$
|
7,065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas property
|
|
|
(1,388
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,756
|
)
|
|
|
|
|
|
|
(5,144
|
)
|
Additions to gathering, transmission and processing facilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(679
|
)
|
|
|
|
|
|
|
(679
|
)
|
Acquisitions, other
|
|
|
(145
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
(150
|
)
|
Short-term investments
|
|
|
(792
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(792
|
)
|
Restricted cash
|
|
|
(14
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14
|
)
|
Proceeds from sales of oil and gas properties
|
|
|
206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
102
|
|
|
|
|
|
|
|
308
|
|
Investment in and advances to subsidiaries, net
|
|
|
(198
|
)
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
211
|
|
|
|
|
|
Other, net
|
|
|
385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(449
|
)
|
|
|
|
|
|
|
(64
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
NET CASH USED IN INVESTING ACTIVITIES
|
|
|
(1,946
|
)
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
(4,787
|
)
|
|
|
211
|
|
|
|
(6,535
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commercial paper, credit facility and bank notes, net
|
|
|
(138
|
)
|
|
|
(7
|
)
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
153
|
|
|
|
(105
|
)
|
|
|
(100
|
)
|
Fixed-rate debt borrowings
|
|
|
796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
796
|
|
Payments on fixed-rate notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends paid
|
|
|
(239
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(239
|
)
|
Common stock activity
|
|
|
31
|
|
|
|
20
|
|
|
|
13
|
|
|
|
(1
|
)
|
|
|
74
|
|
|
|
(106
|
)
|
|
|
31
|
|
Other
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
|
|
494
|
|
|
|
13
|
|
|
|
12
|
|
|
|
(3
|
)
|
|
|
220
|
|
|
|
(211
|
)
|
|
|
525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
|
|
138
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
918
|
|
|
|
|
|
|
|
1,055
|
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
120
|
|
|
|
|
|
|
|
126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
|
$
|
142
|
|
|
$
|
(1
|
)
|
|
$
|
|
|
|
$
|
2
|
|
|
$
|
1,038
|
|
|
$
|
|
|
|
$
|
1,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-65
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
CONDENSED
CONSOLIDATING BALANCE SHEET
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
Apache
|
|
|
Apache
|
|
|
of Apache
|
|
|
Reclassifications
|
|
|
|
|
|
|
Corporation
|
|
|
Finance Canada
|
|
|
Corporation
|
|
|
& Eliminations
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
|
ASSETS
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
6
|
|
|
$
|
|
|
|
$
|
128
|
|
|
$
|
|
|
|
$
|
134
|
|
Receivables, net of allowance
|
|
|
691
|
|
|
|
|
|
|
|
1,443
|
|
|
|
|
|
|
|
2,134
|
|
Inventories
|
|
|
55
|
|
|
|
|
|
|
|
509
|
|
|
|
|
|
|
|
564
|
|
Drilling advances
|
|
|
10
|
|
|
|
2
|
|
|
|
247
|
|
|
|
|
|
|
|
259
|
|
Prepaid assets and other
|
|
|
3,313
|
|
|
|
|
|
|
|
(2,924
|
)
|
|
|
|
|
|
|
389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,075
|
|
|
|
2
|
|
|
|
(597
|
)
|
|
|
|
|
|
|
3,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT, NET
|
|
|
11,314
|
|
|
|
|
|
|
|
26,837
|
|
|
|
|
|
|
|
38,151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany receivable, net
|
|
|
4,695
|
|
|
|
|
|
|
|
(3,149
|
)
|
|
|
(1,546
|
)
|
|
|
|
|
Equity in affiliates
|
|
|
16,649
|
|
|
|
1,275
|
|
|
|
98
|
|
|
|
(18,022
|
)
|
|
|
|
|
Goodwill, net
|
|
|
|
|
|
|
|
|
|
|
1,032
|
|
|
|
|
|
|
|
1,032
|
|
Deferred charges and other
|
|
|
178
|
|
|
|
1,003
|
|
|
|
581
|
|
|
|
(1,000
|
)
|
|
|
762
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
36,911
|
|
|
$
|
2,280
|
|
|
$
|
24,802
|
|
|
$
|
(20,568
|
)
|
|
$
|
43,425
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
480
|
|
|
$
|
2
|
|
|
$
|
1,843
|
|
|
$
|
(1,546
|
)
|
|
$
|
779
|
|
Accrued exploration and development
|
|
|
274
|
|
|
|
|
|
|
|
1,093
|
|
|
|
|
|
|
|
1,367
|
|
Current debt
|
|
|
16
|
|
|
|
|
|
|
|
30
|
|
|
|
|
|
|
|
46
|
|
Asset retirement obligations
|
|
|
317
|
|
|
|
|
|
|
|
90
|
|
|
|
|
|
|
|
407
|
|
Derivative instruments
|
|
|
153
|
|
|
|
|
|
|
|
41
|
|
|
|
|
|
|
|
194
|
|
Other accrued expenses
|
|
|
400
|
|
|
|
3
|
|
|
|
328
|
|
|
|
|
|
|
|
731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,640
|
|
|
|
5
|
|
|
|
3,425
|
|
|
|
(1,546
|
)
|
|
|
3,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT
|
|
|
7,447
|
|
|
|
647
|
|
|
|
1
|
|
|
|
|
|
|
|
8,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes
|
|
|
1,803
|
|
|
|
5
|
|
|
|
2,441
|
|
|
|
|
|
|
|
4,249
|
|
Asset retirement obligation
|
|
|
1,001
|
|
|
|
|
|
|
|
1,464
|
|
|
|
|
|
|
|
2,465
|
|
Other
|
|
|
643
|
|
|
|
250
|
|
|
|
822
|
|
|
|
(1,000
|
)
|
|
|
715
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,447
|
|
|
|
255
|
|
|
|
4,727
|
|
|
|
(1,000
|
)
|
|
|
7,429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS EQUITY
|
|
|
24,377
|
|
|
|
1,373
|
|
|
|
16,649
|
|
|
|
(18,022
|
)
|
|
|
24,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
36,911
|
|
|
$
|
2,280
|
|
|
$
|
24,802
|
|
|
$
|
(20,568
|
)
|
|
$
|
43,425
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-66
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
CONDENSED
CONSOLIDATING BALANCE SHEET
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apache
|
|
|
Apache
|
|
|
of Apache
|
|
|
Reclassifications
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporation
|
|
|
Finance Canada
|
|
|
Corporation
|
|
|
& Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
ASSETS
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
647
|
|
|
$
|
2
|
|
|
$
|
1,399
|
|
|
$
|
|
|
|
$
|
2,048
|
|
|
|
|
|
|
|
|
|
Receivables, net of allowance
|
|
|
575
|
|
|
|
|
|
|
|
971
|
|
|
|
|
|
|
|
1,546
|
|
|
|
|
|
|
|
|
|
Inventories
|
|
|
51
|
|
|
|
|
|
|
|
482
|
|
|
|
|
|
|
|
533
|
|
|
|
|
|
|
|
|
|
Drilling advances
|
|
|
13
|
|
|
|
1
|
|
|
|
217
|
|
|
|
|
|
|
|
231
|
|
|
|
|
|
|
|
|
|
Prepaid assets and other
|
|
|
(16
|
)
|
|
|
|
|
|
|
244
|
|
|
|
|
|
|
|
228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,270
|
|
|
|
3
|
|
|
|
3,313
|
|
|
|
|
|
|
|
4,586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT, NET
|
|
|
9,163
|
|
|
|
|
|
|
|
13,738
|
|
|
|
|
|
|
|
22,901
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany receivable, net
|
|
|
1,839
|
|
|
|
|
|
|
|
(348
|
)
|
|
|
(1,491
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in affiliates
|
|
|
11,243
|
|
|
|
981
|
|
|
|
99
|
|
|
|
(12,323
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill, net
|
|
|
|
|
|
|
|
|
|
|
189
|
|
|
|
|
|
|
|
189
|
|
|
|
|
|
|
|
|
|
Deferred charges and other
|
|
|
134
|
|
|
|
1,003
|
|
|
|
373
|
|
|
|
(1,000
|
)
|
|
|
510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
23,649
|
|
|
$
|
1,987
|
|
|
$
|
17,364
|
|
|
$
|
(14,814
|
)
|
|
$
|
28,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
258
|
|
|
$
|
|
|
|
$
|
1,630
|
|
|
$
|
(1,491
|
)
|
|
$
|
397
|
|
|
|
|
|
|
|
|
|
Accrued exploration and development
|
|
|
247
|
|
|
|
|
|
|
|
676
|
|
|
|
|
|
|
|
923
|
|
|
|
|
|
|
|
|
|
Current debt
|
|
|
|
|
|
|
|
|
|
|
117
|
|
|
|
|
|
|
|
117
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
147
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
|
110
|
|
|
|
|
|
|
|
18
|
|
|
|
|
|
|
|
128
|
|
|
|
|
|
|
|
|
|
Other accrued expenses
|
|
|
237
|
|
|
|
6
|
|
|
|
438
|
|
|
|
|
|
|
|
681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
999
|
|
|
|
6
|
|
|
|
2,879
|
|
|
|
(1,491
|
)
|
|
|
2,393
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT
|
|
|
4,062
|
|
|
|
647
|
|
|
|
241
|
|
|
|
|
|
|
|
4,950
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes
|
|
|
1,306
|
|
|
|
4
|
|
|
|
1,455
|
|
|
|
|
|
|
|
2,765
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation
|
|
|
817
|
|
|
|
|
|
|
|
820
|
|
|
|
|
|
|
|
1,637
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
686
|
|
|
|
250
|
|
|
|
726
|
|
|
|
(1,000
|
)
|
|
|
662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,809
|
|
|
|
254
|
|
|
|
3,001
|
|
|
|
(1,000
|
)
|
|
|
5,064
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS EQUITY
|
|
|
15,779
|
|
|
|
1,080
|
|
|
|
11,243
|
|
|
|
(12,323
|
)
|
|
|
15,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
23,649
|
|
|
$
|
1,987
|
|
|
$
|
17,364
|
|
|
$
|
(14,814
|
)
|
|
$
|
28,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-67
Board of Directors
Frederick M. Bohen (3)(5)
Former Executive Vice President and
Chief Operating Officer,
The Rockefeller University
G. Steven Farris (1)
Chairman and Chief Executive Officer,
Apache Corporation
Randolph M. Ferlic, M.D. (1)(2)
Founder and Former President,
Surgical Services of the Great Plains, P.C.
Eugene C. Fiedorek (2)
Private Investor, Co-Founder and Former
President and Managing Director,
EnCap Investments L.C.
A.D. Frazier, Jr. (3)(5)
Co-Founder and Vice Chairman,
BOTH Holdings, LLC
Patricia Albjerg Graham (4)
Charles Warren Professor of the
History of Education Emerita,
Harvard University
Scott D. Josey
Private Investor, Former Chairman
and Chief Executive Officer,
Mariner Energy, Inc.
Chansoo Joung
Senior Advisor and Former Partner,
Warburg Pincus LLC
John A. Kocur (1)(3)(4)
Attorney at Law; Former Vice Chairman of the Board, Apache
Corporation
George D. Lawrence (1)(3)
Private Investor; Former Chief Executive Officer,
The Phoenix Resource Companies, Inc.
F. H. Merelli (1)(2)
Chairman of the Board, Chief Executive Officer,
and President, Cimarex Energy Co.
Rodman D. Patton (2)
Former Managing Director,
Merrill Lynch Energy Group
Charles J. Pitman (4)
Former Regional President Middle East/
Caspian/Egypt/India, BP Amoco plc
|
|
|
(1)
|
|
Executive Committee
|
|
(2)
|
|
Audit Committee
|
|
(3)
|
|
Management Development and
Compensation
Committee
|
|
(4)
|
|
Corporate Governance and Nominating
Committee
|
|
(5)
|
|
Stock Option Plan Committee
|
Officers
G. Steven Farris
Chairman and Chief Executive Officer
Roger B. Plank
President
John A. Crum
Co-Chief Operating Officer and
President
North America
Rodney J. Eichler
Co-Chief Operating Officer and
President International
Michael S. Bahorich
Executive Vice President, Chief
Technology Officer
Thomas P. Chambers
Executive Vice President and Chief
Financial Officer
Jon A. Jeppesen
Executive Vice President
P. Anthony Lannie
Executive Vice President and
General Counsel
W. Kregg Olson
Executive Vice
President Corporate Reservoir
Engineering
Matthew W. Dundrea
Senior Vice President
Treasury and Administration
Robert J. Dye
Senior Vice President
Global Communication and
Corporate Affairs
Margie Harris
Senior Vice President
Human Resources
Janine J. McArdle
Senior Vice President
Gas Monetization
Sarah B. Teslik
Senior Vice President
Policy and Governance
John R. Bedingfield
Vice President
Worldwide Exploration and New Ventures
David A. Carmony
Vice President
Environmental, Health and Safety
Rod Gryder
Vice President Audit
David L. French
Vice President Business
Development
Rebecca A. Hoyt
Vice President, Chief Accounting
Officer and Controller
Alfonso Leon
Vice President
Planning, Strategy and Investor Relations
Aaron S. G. Merrick
Vice President
Information Technology
Urban F. OBrien
Vice President
Government Affairs
Jon W. Sauer
Vice President Tax
Cheri L. Peper
Corporate Secretary
Shareholder
Information
Stock Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
Price Range
|
|
|
per Share
|
|
|
|
High
|
|
|
Low
|
|
|
Declared
|
|
|
Paid
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
108.92
|
|
|
$
|
95.15
|
|
|
$
|
.15
|
|
|
$
|
.15
|
|
Second Quarter
|
|
|
111.00
|
|
|
|
83.55
|
|
|
|
.15
|
|
|
|
.15
|
|
Third Quarter
|
|
|
99.09
|
|
|
|
81.94
|
|
|
|
.15
|
|
|
|
.15
|
|
Fourth Quarter
|
|
|
120.80
|
|
|
|
96.51
|
|
|
|
.15
|
|
|
|
.15
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
88.07
|
|
|
$
|
51.03
|
|
|
$
|
.15
|
|
|
$
|
.15
|
|
Second Quarter
|
|
|
87.04
|
|
|
|
61.60
|
|
|
|
.15
|
|
|
|
.15
|
|
Third Quarter
|
|
|
95.77
|
|
|
|
65.02
|
|
|
|
.15
|
|
|
|
.15
|
|
Fourth Quarter
|
|
|
106.46
|
|
|
|
88.06
|
|
|
|
.15
|
|
|
|
.15
|
|
The Company has paid cash dividends on its common stock for 46
consecutive years through December 31, 2010. Future
dividend payments will depend upon the Companys level of
earnings, financial requirements and other relevant factors.
Apache common stock is listed on the New York and Chicago stock
exchanges and the NASDAQ National Market (symbol APA). At
December 31, 2010, the Companys shares of common
stock outstanding were held by approximately
5,700 shareholders of record and 440,000 beneficial owners.
Also listed on the New York Stock Exchange are:
|
|
|
|
|
Apache Depositary shares (symbol APA/PD), each representing a
1/20th interest in Apaches 6% Mandatory Convertible
Preferred Stock, Series D
|
|
|
|
Apache Finance Canadas 7.75% notes, due 2029 (symbol
APA/29)
|
Corporate Offices
One Post Oak Central
2000 Post Oak Boulevard
Suite 100
Houston, Texas
77056-4400
(713) 296-6000
Independent Public Accountants
Ernst & Young LLP
Five Houston Center
1401 McKinney Street, Suite 1200
Houston, Texas
77010-2007
Stock Transfer Agent and Registrar
Wells Fargo Bank, N.A.
Attn: Shareowner Services
P.O. Box 64854
South St. Paul, Minnesota
55164-0854
(651) 450-4064
or
(800) 468-9716
Communications concerning the transfer of shares, lost
certificates, dividend checks, duplicate mailings or change of
address should be directed to the stock transfer agent.
Shareholders can access account information on the web site:
www.shareowneronline.com
Dividend
Reinvestment Plan
Shareholders of record may invest their dividends automatically
in additional shares of Apache common stock at the market price.
Participants may also invest up to an additional $25,000 in
Apache shares each quarter through this service. All bank
service fees and brokerage commissions on purchases are paid by
Apache. A prospectus describing the terms of the Plan and an
authorization form may be obtained from the Companys stock
transfer agent, Wells Fargo Bank, N.A.
Direct
Registration
Shareholders of record may hold their shares of Apache common
stock in book-entry form. This eliminates costs related to
safekeeping or replacing paper stock certificates. In addition,
shareholders of record may request electronic movement of
book-entry shares between your account with the Companys
stock transfer agent and your broker. Stock certificates may be
converted to book-entry shares at any time. Questions regarding
this service may be directed to the Companys stock
transfer agent, Wells Fargo Bank, N.A.
Annual
Meeting
Apache will hold its annual meeting of shareholders on Thursday,
May 5, 2011, at 10:00 a.m. in the Ballroom, Hilton
Houston Post Oak, 2001 Post Oak Boulevard, Houston, Texas.
Apache plans to web cast the annual meeting live; connect
through the Apache web site: www.apachecorp.com
Stock
Held in Street Name
The Company maintains a direct mailing list to ensure that
shareholders with stock held in brokerage accounts receive
information on a timely basis. Shareholders wanting to be added
to this list should direct their requests to Apaches
Public and International Affairs Department, 2000 Post Oak
Boulevard, Suite 100, Houston, Texas,
77056-4400,
by calling
(713) 296-6157
or by registering on Apaches web site: www.apachecorp.com
Form 10-K
Request
Shareholders and other persons interested in obtaining, without
cost, a copy of the Companys
Form 10-K
filed with the Securities and Exchange Commission may do so by
writing to Cheri L. Peper, Corporate Secretary, 2000 Post Oak
Boulevard, Suite 100, Houston, Texas,
77056-4400.
Investor
Relations
Shareholders, brokers, securities analysts or portfolio managers
seeking information about the Company are welcome to contact
Alfonso Leon, Vice President, Planning, Strategy and Investor
Relations, at
(713) 296-6692.
Members of the news media and others seeking information about
the Company should contact Apaches Public and
International Affairs Department at
(713) 296-7276.
Web site:
www.apachecorp.com