APACHE CORP
10-Qs and 10-Ks
PROXIES
Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
FORM 10-K
| (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 | |
| For the fiscal year ended December 31, 2009 | ||
| OR | ||
|
o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the transition period from to |
Commission file number 1-4300
APACHE CORPORATION
(Exact name of registrant as
specified in its charter)
|
Delaware
(State or other jurisdiction of incorporation or organization) |
41-0747868
(I.R.S. Employer Identification No.) |
One Post Oak Central, 2000 Post Oak Boulevard,
Suite 100, Houston, Texas
77056-4400
(Address of principal executive offices)
Registrant’s 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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||
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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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||
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Irrevocably and Unconditionally
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||
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Guaranteed by Apache Corporation
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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 Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule-405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes
þ
No
o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K.
o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
“large accelerated filer,” “accelerated
filer” and “smaller reporting company” in Rule
12b-2
of the
Exchange Act. (Check one):
| Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
(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
|
Aggregate market value of the voting and non-voting common
equity held by non-affiliates of registrant as of June 30,
2009
|
$ | 24,224,151,606 | ||
|
Number of shares of registrant’s common stock outstanding
as of January 31, 2010
|
336,550,234 |
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of registrant’s proxy statement relating to
registrant’s 2010 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
2
Table of Contents
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.
“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.
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.
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Table of Contents
PART I
ITEMS 1
AND 2.
BUSINESS AND PROPERTIES
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. In
North America, our exploration and production interests are
focused in the Gulf of Mexico, the Gulf Coast, East Texas, the
Permian Basin, the Anadarko Basin and the Western Sedimentary
Basin of Canada. Outside of North America, we have exploration
and production interests onshore Egypt, offshore Western
Australia, offshore the U.K. in the North Sea (North Sea), and
onshore Argentina. We also have exploration interests on the
Chilean side of the island of Tierra del Fuego. 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 19, 2009, we filed
certifications of our compliance with the listing standards of
the NYSE and the NASDAQ, including our principal executive
officer’s 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
Apache’s 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 SEC’s 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 United States (U.S.), Canadian
and other international properties through subsidiaries,
including Apache Canada Ltd., DEK Energy Company (DEKALB),
Apache Energy Limited (AEL), Apache North America, Inc. and
Apache Overseas, Inc. 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
Apache’s mission is to grow a profitable upstream oil and
gas company for the long-term benefit of our shareholders.
Apache’s long-term perspective has many dimensions, with
the following core principles:
| • | own a balanced portfolio of core assets; | |
| • | maintain financial flexibility and a strong balance sheet; and | |
| • | optimize rates of return, earnings and cash flow. |
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 24 years and production 29 out
of the past 31 years, a testament to our consistency over
the long-term.
Portfolio
of Assets
We own a portfolio of assets in core areas that provide
opportunities for growth through drilling, supplemented by
occasional strategic acquisitions. Over the last two decades, we
have assembled a large acreage position and
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Table of Contents
production base outside the United States that provide
additional geologic and geographic opportunities, diversifying
risk, and provide exposure to larger reserve targets, which fuel
production and reserve growth. We now have exploration and
production operations in six countries, spanning five
continents: the Gulf Coast and Central regions in the United
States (U.S.), Canada, Egypt, the North Sea, Australia and
Argentina. We also have exploration interests in Chile located
adjacent to our Argentine operations on the Chilean side of the
island of Tierra del Fuego.
Each of our producing regions has achieved an economy of scale
that leads to cost effective production and sustainable,
lower-risk, repeatable drilling opportunities. The net cash
provided by operating activities (cash flow) generated by our
current production base and our 33 million gross acres
across the globe provide the ability to pursue new exploration
targets while developing our previous exploration discoveries.
Those developments will fund the next round of exploration
activities and development programs.
We manage our investments giving consideration to geography,
reserve life and hydrocarbon mix.
| • | No single region contributed more than 27 percent of our equivalent production or reserves in 2009. | |
| • | The mixture of reserve life (estimated reserves divided by annual production) in our regions, which translates into balance in the timing of returns on our investments, ranges from as short as six years to as long as 21 years. | |
| • | 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 2009 crude oil and liquids provided 50 percent of our production and 72 percent of our revenue. At year-end, our estimated proved reserves were 45 percent crude oil and liquids and 55 percent natural gas. |
Financial
Flexibility and a Strong Balance Sheet
Apache’s financial flexibility is the result of years of
hard work and discipline. This flexibility permits us to pursue
higher-risk, higher-reward exploration targets, to develop
large-scale facilities required to produce previous exploration
discoveries and, when appropriate, to supplement our drilling
and exploration programs with value-creating acquisitions.
Given the turmoil in the commodity markets and nearly
unprecedented global financial crisis at the outset of the year,
Apache’s primary objective for 2009 was to live within our
cash flow and preserve our financial flexibility. To ensure we
lived within cash flow, we reduced our 2009 activity and
invested $4.1 billion, 39 percent below 2008 levels.
Apache grew production nine percent and generated
$4.2 billion in cash flow in 2009 in spite of curtailed
capital spending. We exited 2009 with a
debt-to-capitalization
ratio of 24 percent, just over $2 billion of cash and
$2.3 billion in available committed borrowing capacity. We
also believe our single-A debt ratings provide a competitive
advantage in accessing capital markets.
Optimize
Returns on Invested Capital
We focus on optimizing returns on invested capital through
strict cost control and the creative application of technology.
Our management systems provide a uniform process of measuring
success across Apache. Our management systems 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 monitor capital allocations, at least
quarterly, through a disciplined and focused process that
includes analyzing current economic conditions, expected rates
of return on proposed development and exploration drilling
targets, opportunities for tactical acquisitions or,
occasionally, new core areas that could enhance our portfolio.
We also use technology to optimize our rates of return by
reducing risk, decreasing drilling time and costs, and
maximizing recoveries from reservoirs. Additionally, Apache
scientists and engineers have been granted numerous
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Table of Contents
patents for a range of inventions, from systems used for
interpreting seismic data or processing well logs to
improvements in drilling and completion techniques.
One such example is a manifold invented for development of 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 for a manifold that will
connect all 16 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 increase
Apache’s rate of return on potentially thousands of future
wells across our leasehold.
At our Forties field, 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 three-dimensional
seismic surveys, is utilized by Apache to create a time-lapse
picture that shows where oil remains after 35 years of
production. The latest model of the reservoir highlighted the
potential for stranded oil accumulations in close proximity to
the Charlie platform and helped Apache’s technical teams
identify the Charlie 6-3 target drilled in 2009. The well came
on production at 10,500 b/d — the field’s highest
initial production rate from a new well since 1994.
For a more in-depth discussion of our 2009 results and the
Company’s capital resources and liquidity, please see
Part II, Item 7 — Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.
Geographic
Area Overviews
We currently have exploration and production interests in six
countries, divided into seven operating regions: the United
States (Gulf Coast and Central regions), Canada, Egypt,
Australia, offshore the United Kingdom in the North Sea and
Argentina. We also have exploration interests on the Chilean
side of the island of Tierra del Fuego, which we acquired in the
second quarter of 2008.
The following table sets out a brief comparative summary of
certain key 2009 data for each of our operating areas.
Additional data and discussion is provided in Part II,
Item 7 of this
Form 10-K.
|
Percentage
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2009
|
2009 Gross
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||||||||||||||||||||||||||
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Percentage
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12/31/09
|
of Total
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Gross
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New
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||||||||||||||||||||||||
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of Total
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2009
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Estimated
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Estimated
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New
|
Productive
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|||||||||||||||||||||||
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2009
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2009
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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 | Production | Revenue | Reserves | Reserves | Drilled | Drilled | ||||||||||||||||||||||
| (In MMboe) | (In millions) | (In MMboe) | ||||||||||||||||||||||||||
|
Region/Country:
|
||||||||||||||||||||||||||||
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Gulf Coast
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42.8 | 20 | % | $ | 1,814 | 300.0 | 13 | % | 26 | 15 | ||||||||||||||||||
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Central
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32.5 | 15 | 1,236 | 630.0 | 27 | 135 | 133 | |||||||||||||||||||||
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Total U.S.
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75.3 | 35 | 3,050 | 930.0 | 40 | 161 | 148 | |||||||||||||||||||||
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Canada
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28.2 | 13 | 877 | 531.0 | 22 | 201 | 188 | |||||||||||||||||||||
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Total North America
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103.5 | 48 | 3,927 | 1,461.0 | 62 | 362 | 336 | |||||||||||||||||||||
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Egypt
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55.7 | 26 | 2,553 | 308.8 | 13 | 164 | 147 | |||||||||||||||||||||
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Australia
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14.7 | 7 | 363 | 305.3 | 13 | 33 | 28 | |||||||||||||||||||||
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North Sea
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22.4 | 11 | 1,369 | 172.5 | 7 | 17 | 14 | |||||||||||||||||||||
|
Argentina
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16.6 | 8 | 362 | 119.0 | 5 | 32 | 31 | |||||||||||||||||||||
|
Other International
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— | — | — | — | — | 2 | 2 | |||||||||||||||||||||
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Total International
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109.4 | 52 | 4,647 | 905.6 | 38 | 248 | 222 | |||||||||||||||||||||
|
Total
|
212.9 | 100 | % | $ | 8,574 | 2,366.6 | 100 | % | 610 | 558 | ||||||||||||||||||
North
America
Apache’s North American asset base comprises the
U.S. Central region, U.S. Gulf Coast region and our
Canada region. Oil and liquids production, mainly from the
U.S. Permian Basin and the Gulf of Mexico, made up
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nearly 40 percent of North America’s
2009 barrel-equivalent production and 46 percent of
North America’s year-end estimated proved reserves. Our
North American production is also balanced between the shorter
reserve life but higher rates of return in the Gulf of Mexico
and longer reserve life for Apache’s onshore assets in
Canada and the Permian and Anadarko Basins of the United States.
As result of past growth and future opportunities available in
the Central region, we have created a new regional unit
beginning in 2010. Our Permian region will be based in Midland,
Texas and will be responsible for our Permian Basin business.
The Central region will focus on our extensive holdings in
Oklahoma, East Texas and the Texas Panhandle, especially the
Granite Wash play.
The identification and commercialization of significant
resources in shale formations and other unconventional gas plays
has changed the natural gas markets for the foreseeable future,
with current estimates that North America has a
100-year
resource of natural gas. Although Apache’s current
production in North America is primarily conventional, near-term
growth will likely be driven by activity in two large growth
plays: shale gas in British Columbia’s Horn River Basin and
the Granite Wash tight sands in the Anadarko Basin of Oklahoma
and the Texas Panhandle. Apache has identified many years of
drilling activity in both plays.
We anticipate that the increased supply of natural gas will
ultimately encourage producers to seek new and unconventional
markets for their supply. Apache is one of the first independent
producers to seek global markets for its North American natural
gas production through our acquisition of a 51-percent ownership
and throughput capacity interest in the proposed Kitimat LNG
Terminal in British Columbia.
In order to live within expected cash flow, Apache curtailed
exploration and development capital at the outset of 2009. In
North America we drilled 362 gross wells, down from
1,015 wells in 2008. Exploration, drilling, and acquisition
spending totaled $1.6 billion in 2009, 49 percent
lower than in 2008. Despite lower activity and spending, we
added 122.3 MMboe of estimated proved reserves through
drilling and acquisitions in North America, 18.8 MMboe more
than the 103.5 MMboe produced. Equivalent production from
our North American regions declined one percent
year-over-year.
We are ramping up activity in early 2010 as we move into
development mode at Horn River, increase drilling in the Granite
Wash formation and double our oil drilling activity in the
Permian Basin. In 2010, we currently plan to drill or
participate in 561 gross wells in North America.
United
States
Overview
In the U.S., the Gulf Coast
region’s assets, balanced between oil and natural gas,
historically generate high rates of return on invested capital.
Occasional acquisitions have played an important role, as steep
decline rates mean offshore reserves are generally shorter-lived
and difficult to replace on a cost-effective basis through
drilling alone. The Central region brings the balance of
long-lived reserves and consistent drilling results to the
portfolio.
Gulf Coast Region
This region comprises our
interests in and along the Gulf of Mexico, in the areas on and
offshore Louisiana and Texas. Apache has been the largest
held-by-production
acreage owner since 2004, and the second largest producer on the
Outer Continental Shelf of the Gulf of Mexico (waters less than
1,200 feet deep). The region also holds 1.2 million
gross acres along the Gulf Coast of Louisiana and Texas. In 2009
the region contributed approximately 20 percent of our
worldwide production, about 21 percent of our revenues and,
at year-end, held nearly 13 percent of our estimated proved
reserves.
The region had a productive year despite the capital curtailment
stemming from lower commodity prices at the end of 2008. The
region drilled or participated in 26 wells, down from
116 wells in 2008, and performed 217 workovers and
recompletions.
In May 2009 production commenced from two deepwater wells in the
Geauxpher field, located on Garden Banks Block 462. During
the second half of 2009, the field produced an average of
91 MMcf/d
gross. Apache generated the prospect and has a 40-percent
working interest. We also announced another key deepwater
discovery
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in April 2009 at Ewing Banks 998 that test-flowed 4,254 b/d and
5.4 MMcf/d.
The well will be connected to existing facilities, with first
production projected for mid-year 2010. Apache owns a 50-percent
interest in the property.
The risk of hurricanes in the Gulf Coast region has been an
ongoing issue. Frequency, intensity and location of major
hurricanes is impossible to predict. The majority of our Gulf of
Mexico assets have enjoyed full-life cycles without suffering
significant storm-related damage. While facilities are designed
to withstand severe weather, they may incur significant damage
when confronted by the most extreme hurricane conditions. Also,
with mature facilities, proactive management includes aggressive
well and equipment abandonment that should minimize the
environmental impact and reduce the eventual cost of remediation.
This damage may result in expenses for repairs to restore
production as well as expenses to remove and abandon wreckage.
During 2009, approximately $64 million in excess of
insurance proceeds was spent to repair damage stemming from 2008
hurricanes. An additional $260 million in excess of
insurance proceeds was expended for the continued abandonment
and removal of wreckage from platforms toppled in hurricanes.
Cash expended for abandonment activities reduces our asset
retirement obligation. The majority of the hurricane abandonment
work is now complete.
During 2010 the region plans to invest approximately
$1.3 billion to $1.4 billion for drilling,
recompletion projects, development projects, equipment upgrades,
production enhancement projects, seismic acquisition and
abandonment activities.
Central Region
The Central region includes
assets in the Anadarko Basin, the East Texas Basin and the
Permian Basin. Over the past decade, the region has grown from
approximately 3,000 wells to over 10,000 and now represents
27 percent of Apache’s proved reserves, the largest
concentration in the Company. The region provides steady,
predictable results, enhanced by assets across a large acreage
base. During 2009 Apache operated or participated in drilling
135 wells; 99 percent were completed as producers. The
region also performed 810 workovers and recompletions.
In 2009 we drilled our first operated horizontal well in the
Granite Wash play in Washita County, Oklahoma. The
Hostetter #1-23H commenced production in September 2009 at
17 MMcf/d
and 800 b/d and is currently producing
9.5 MMcf/d
and 600 b/d. Apache owns a 72-percent working interest in the
well. The Granite Wash has long been a core-stacked pay target
for the Central Region, where we have drilled many vertical
wells over the past decade. As a result, we control
approximately 200,000 gross acres in the 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 high
oil prices given the rich liquids yield of the wells. Hundreds
of additional horizontal well locations have been identified
across our acreage, extending opportunities for many years. In
early 2010 we had three rigs in operation with plans to increase
to at least five as we target drilling a minimum of 29
horizontal wells in the play during the year.
During 2010 the Central region plans to invest approximately
$325 million to $375 million for drilling,
recompletion projects, development projects, equipment upgrades,
production enhancement projects and seismic acquisition in the
Anadarko Basin and East Texas. Our newly formed Permian Region
plans to invest approximately $375 million to
$400 million for similar activities, primarily directed at
oil targets.
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.
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
At year-end 2009 our Canadian region
held approximately 22 percent of our estimated proved
reserves, the second largest concentration in the Company. In
our Canadian region, we have 4.4 million net acres
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across the provinces of British Columbia, Alberta and
Saskatchewan. 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. In 2009 we drilled or participated in
201 wells in Canada, 41 of which were in the Horn River
Basin. Three of the region’s wells drilled during the year
were exploration wells, all of which were productive.
Apache and EnCana Corporation (EnCana), 50-percent partners,
control more than 400,000 acres in the Horn River Basin
shale-gas play in northeast British Columbia. We estimate that
we could ultimately drill thousands of wells. In 2009
Apache and EnCana drilled 41 wells in the Basin: 23 by
Apache and 18 by EnCana. To minimize the environmental footprint
and costs, the wells are drilled in batches from multi-well
pads. Completion activity commences once drilling operations
from a single pad have been completed, allowing room for the
equipment needed for fracturing operations to service the entire
pad. Four of the EnCana-operated wells were placed on production
in 2009 and at year-end were producing at a combined gross rate
in excess of
19 MMcf/d.
Apache commenced stimulating the 16 wells on its first
operated development pad in the fourth quarter of 2009, with
production scheduled for mid-2010.
The magnitude of the Horn River resource, its remote location,
and the desire to maximize returns prompted Apache to seek
alternative markets for its natural gas. On January 13,
2010, we announced that our Apache Canada Ltd. subsidiary agreed
to acquire 51-percent ownership and throughput capacity interest
in Kitimat LNG Inc.’s proposed LNG export terminal in
northern British Columbia. We expect to begin front-end
engineering and design (FEED) of the project in early 2010. If
we proceed with development, Apache’s net capacity in the
facility will provide an outlet for
350 MMcf/d
from Horn River and other areas in Canada, providing access to
markets with worldwide LNG prices. Preliminary gross
construction cost estimates, which will be refined upon
completion of the FEED study, total C$3 billion. A final
investment decision (FID) is expected in 2011. If we proceed,
initial gas exports are forecast for as early as 2014. Kitimat
is designed to be linked to the pipeline system servicing
Western Canada’s natural gas producing regions via the
proposed Pacific Trail Pipelines, a C$1.1 billion project.
In association with our acquisition of interest in the Kitimat
project, we also acquired a 25.5-percent interest in the
proposed pipeline and 350 MMcf/d of capacity rights.
In December 2009, we entered into a farm-in agreement with
Corridor Resources Inc. (Corridor) to appraise and potentially
develop oil and natural gas resources in the province of New
Brunswick. The initial
18-month
program is intended to evaluate the commercial potential of
natural gas development in the Frederick Brook formation and
light oil development at a recent Caledonia oil discovery at a
cost to Apache of not less than $25 million. Upon
completion of this appraisal program, Apache will have earned a
50-percent working interest in the spacing units drilled. Apache
will then have the option to participate in phase two of the
program at a cost of not less than $100 million. Upon
completion of this phase by March 31, 2013, Apache would
earn a 50-percent interest in approximately 116,000 acres.
Our plans for 2010 are to drill or participate in a total of
172 wells in Canada, including 156 development wells
and 16 exploratory wells. The planned development wells include
34 new wells in the Horn River Basin, with Apache drilling 18
and EnCana drilling 16. We believe our production will continue
to
ramp-up
in this area throughout 2010 with completion of 55 wells
from Apache and its Horn River partner’s drilling programs.
During 2010 the region plans to invest approximately
$1.0 billion to $1.1 billion for drilling,
recompletion projects, development projects, equipment upgrades,
production enhancement projects and seismic acquisition.
Approximately $100 million of the total is for gathering,
transportation and processing (GTP) assets.
On our other core properties, we will focus on oil projects
located primarily in Alberta and Saskatchewan to take advantage
of the current vast discrepancies between oil and gas 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 (EOR) projects in Midale, Zama and Provost with
long-term plans to develop and expand
CO
2
projects. We will continue intermediate-depth gas development
drilling in Kaybob and West 5 areas and in Nevis for shallow
coal bed methane (CBM) gas. In addition, pursuant to our
December 2009 farm-in agreement with Corridor, Apache will
commence an appraisal program in New Brunswick in 2010.
9
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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. Improved North American natural gas pipeline
connectivity led to a closer correlation between Canadian and
U.S. natural gas prices. 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 2009 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 and our NGLs based on postings, both of which are
market-reflective prices, adjusted for quality, transportation
and a 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.
Egypt
Overview
Egypt holds our largest acreage
position, with more than 11 million gross acres in 21
separate concessions (18 producing) that provide us considerable
exploration and development opportunities. In addition to being
the largest acreage holder in Egypt’s Western Desert, we
believe that Apache is also the largest producer of liquid
hydrocarbons and natural gas in the Western Desert and the third
largest in all of Egypt. In 2009 our Egypt region contributed
30 percent of Apache’s production revenue,
26 percent of total production and 13 percent of total
estimated proved reserves. The Company reports all estimated
proved reserves held under production sharing agreements
utilizing the economic interest method, which excludes the host
country’s share of reserves. In 2009 Apache had an active
drilling program in Egypt, drilling 164 wells, including
nine new field discoveries, and conducted 792 workovers and
recompletions. Historically, our growth in Egypt has been driven
primarily by exploration and development of internally-generated
prospects; in 2009 we were the most active driller in Egypt.
In the Khalda concession in 2009, we continued to monetize our
Qasr gas discovery through completion of two additional Salam
gas processing facilities, trains three and four, and an
associated pipeline compression project on the Western Desert
Northern Gas Pipeline. These facility expansions increased flow
rates from our Qasr field discovery to
600 MMcf/d
and increased total net production in Egypt by
100 MMcf/d
and 5,000 b/d.
In Egypt, our operations are conducted pursuant to
production-sharing contracts 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. In general, the
balance of the production is allocated between the contractor
partners and Egyptian General Petroleum Corporation (EGPC) on a
contractually defined basis. Development leases within
concessions generally have a
25-year
life, with extensions possible for additional commercial
discoveries or on a negotiated basis.
During 2010 the region plans to invest approximately
$1.0 billion to $1.1 billion for drilling,
recompletion projects, development projects, equipment upgrades,
production enhancement projects and seismic acquisition.
Approximately $150 million of the total is for GTP assets.
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 $3.70 per Mcf in 2009.
Oil from the Khalda Concession, the Qarun Concession and other
nearby Western Desert blocks is sold to EGPC when called upon to
supply domestic demand
and/or
to
third parties primarily in the Mediterranean market. Oil sales
are made either directly into the Egyptian oil pipeline grid,
sold to non-governmental third parties
10
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including 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 2009 we sold 47 cargoes
(approximately 14.7 million barrels) 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
quality oil (approximately 8.5 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 (1.7 MMbbls) or
exported primarily to refiners in the Mediterranean region (14
cargoes for approximately 6.8 MMbbls). While we anticipate
that an increasing amount of our oil will be sold to meet
domestic demand during 2010, we still expect some level of sales
to the export market.
Australia
Overview
In Australia our exploration activity
is focused in the offshore Carnarvon, Gippsland and Browse
Basins, where Apache holds 4.3 million net acres in 31
exploration permits, 14 production licenses and three retention
leases. We also have one production license and two retention
leases pending confirmation. Production operations are
concentrated in the Carnarvon and Exmouth Basins. In 2009 the
region increased equivalent production 40 percent and
accounted for approximately seven percent of our total
production. Australia held 13 percent of our year-end
estimated proved reserves. During the year the region
participated in drilling 33 wells, which generated 28
productive wells.
During 2009 the Australia region restored operations and
increased capacity at our Varanus Island gas processing
facility, and continued to lay the foundation for future growth
by developing previously discovered fields that will come online
over the short, intermediate and long terms.
Our growth strategy includes short-term, medium-term and
long-term projects from the Carnarvon Basin off the North West
shelf of Australia. Both Van Gogh and Pyrenees (two large oil
development projects in the Exmouth
sub-basin)
commenced production in the first quarter of 2010. In the
intermediate-term, growth in Australia will result from the
development of both Apache’s 2008 Halyard discovery and our
Reindeer discovery. Both Halyard and Reindeer are
gas-development projects that are scheduled to initiate
production in 2011. Long-term growth will come from the
Company’s Julimar, Macedon and Coniston discoveries.
Growth Drivers 2010
Van Gogh is
Apache-operated, while Pyrenees is operated by BHP Billiton. Van
Gogh development drilling and installation of sub sea production
equipment was completed in mid-2009, and limited production
commenced in mid-February 2010. Van Gogh oil is produced and
stored in the Ningaloo Vision floating, production, storage and
offloading (FPSO) vessel, which is still performing normal
commissioning activities.
Pyrenees development continued with the drilling and completion
of initial wells and installation of subsea facilities in 2009.
First oil production commenced ahead of schedule, on
February 24, 2010. As planned, the wells will be drilled
and brought on in phases, with half of the expected production
volume ramping up over the next six months.
Peak production from the Van Gogh and Pyrenees discoveries is
projected to reach a combined 40,000 b/d net to Apache.
During 2010 the region plans to invest approximately
$1.1 billion to $1.2 billion for drilling,
recompletion projects, development projects, equipment upgrades,
production enhancement projects and seismic acquisition.
Approximately $350 million of the total is for development
and processing facilities.
Growth Drivers 2011
In April 2008 we drilled
the Halyard-1 discovery well, which tested
68 MMcf/d.
Current plans call for the field to be tied into the nearby East
Spar gas facilities, with first production anticipated in 2011.
Construction and fabrication work has resumed and official
groundbreaking at the Devil Creek site of the onshore gas plant
was on September 15, 2009, following completion of a gas
sales contract with CITIC Pacific’s Sino Iron project in
Western Australia. This plant and gas sales contract will enable
us to monetize a portion of our
11
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Reindeer gas discovery. Under terms of the agreement, Apache and
its joint venture partner have agreed to supply 154 Bcf of
gas over seven years (approximately
60 MMcf/d)
beginning in the second half of 2011 at prices substantially
above Apache’s current average realizations. Apache owns a
55-percent interest in the field. The Company is continuing to
market its remaining net share in the Reindeer field.
Growth Drivers — Long-Term
Apache
has agreed to participate in an LNG development project
(discussed below) that will enable Apache to develop and
monetize its share of the Julimar and Brunello natural gas
discoveries, opening up new markets for these reserves.
Apache’s projected net sales are
190 MMcf/d
and 5,100 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 tied to oil prices and are currently higher
than the historical gas prices in Western Australia.
In October 2009 we announced Apache’s 16.25 percent
participation with Chevron in the Wheatstone LNG project. The
Wheatstone project is targeting a FID in 2011, with first LNG
projected in 2015. Apache operates the Julimar and Brunello
fields, while Chevron will operate both the Wheatstone field and
the LNG facilities. Our net capital investment in the project is
currently estimated to be $1.2 billion for upstream
development of the Julimar and Brunello fields and
$3.0 billion in the Wheatstone facilities.
We have two contingent development opportunities tied to our
recent Pyrenees and Van Gogh projects that will be evaluated
during 2010. Macedon field is a gas discovery near the Pyrenees
field that is currently under review by the operator, BHP
Billiton, for commercial development. Gas produced from Pyrenees
will be reinjected into Macedon field to reduce flaring and to
conserve those volumes for future sale. Coniston field is an oil
accumulation near our Van Gogh field. Apache has drilled 10
appraisal wells during 2009 and is evaluating a development plan
to tie back the field to the FPSO Ningaloo Vision currently
serving the Van Gogh field.
Marketing
As of December 31, 2009, Apache
had a total of 18 active gas contracts in Australia with
expiration dates ranging from March 2010 to July 2030.
Historically, natural gas sold in Western Australia was under
long-term, fixed-price contracts, many of which contain price
escalation clauses based on the Australian consumer price index.
The contract in place for the Reindeer field contains prices
substantially higher than we currently receive in Australia. The
LNG from our Julimar discovery is anticipated to be sold at
prices tied to oil and sold into international markets.
Apache continues to directly market all of its crude oil
production into Australian domestic and international markets at
prices generally indexed to Dated Brent or Tapis benchmarks,
which typically track at or above NYMEX oil prices.
North
Sea
Overview
Apache entered the North Sea in 2003
upon acquiring an approximate 97-percent working interest in the
Forties field (Forties). Production for 2009 increased two
percent compared to 2008 as gains from our topsides renovation
program and our drilling and workover programs more than offset
downtime to replace an original vintage spool section at the end
of the Bravo-Charlie infield pipeline, which lowered production
for the year by 2,690 boe/d.
In addition to an active year of drilling, we completed and made
significant progress on several important facility projects that
will benefit Forties in the years ahead. The Delta-Charlie
infield pipeline was replaced, bringing improved mechanical
integrity. We installed and commissioned a new power turbine on
Delta to support increasing field-water injection during 2010.
On the Charlie platform, we purchased equipment, cleared access
and began installing components late in 2009 for a new
high-pressure gas lift system that will be operational in early
2011. Work that began on the Echo platform several years ago to
replace the antiquated and unreliable controls system with a
modern version was fundamentally completed. The various facility
upgrade and improvement projects completed in recent years
resulted in a significant reduction in the number of occurrences
of unplanned downtime. In 2009 we had fewer events causing
unplanned downtime than we have experienced in any year since
acquiring the Forties field; 64 percent less than our previous
best year.
12
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In 2009 the North Sea region produced 22.4 MMboe
(99 percent oil), approximately 11 percent of our
total worldwide production, generating almost $1.4 billion
of revenue and held approximately seven percent of our year-end
estimated proved reserves. Our capital investments in the North
Sea region during 2009 totaled $354 million.
During 2010 the region plans to invest approximately
$625 million to $675 million with significant capital
devoted to drilling and improving facilities within Forties. We
will also shoot a
3-D
seismic
survey over Forties to refresh our four-dimensional imaging of
bypassed oil accumulations. In 2010 we expect to drill at least
one exploration well and one appraisal well in waters outside
Forties.
Marketing
In 2009 we sold our Forties crude
under both term contracts and spot cargoes. The term sales are
composed of base-market indices, adjusted for the quality
difference between the Forties crude and Brent, with a premium
to reflect the higher market value for term arrangements. The
value received for spot cargoes, generally about
600,000 barrels each, were at or above prevailing market
prices. Apache sold 12 spot cargoes in 2009.
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 and Tierra del Fuego. We
have interests in 24 concessions covering over 3.1 million
gross acres (2.8 million net), with varying expiration
dates, but generally greater than 10 years remaining subject to
additional extensions.
Natural gas price realizations in Argentina continued their
upward trend in 2009. Our 2009 realized prices were $1.96 per
Mcf, a 22 percent increase over our 2008 averaged realized
price of $1.61 per Mcf and a 68 percent increase over the
$1.17 per Mcf realized in 2007.
During 2009 Apache received technical and commercial approval
from the government of Argentina for four Gas Plus projects and
technical approval for two more Gas Plus projects designed to
encourage new supplies through development of tight sands and
unconventional gas reserves. Under the Gas Plus program, Apache
has the opportunity to supply
10 MMcf/d
from fields in the Neuquén Province at a price of $4.10 per
MMBtu beginning January 2010 for an initial one-year term. The
Company also has signed a letter of intent for a contract to
supply up to
50 MMcf/d
from fields in the Neuquén and Rio Negro Provinces for
$5.00 per MMBtu beginning January 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 this type of program, coupled with changing market
conditions, points to improving price realizations going forward.
In December 2008 the Mendoza Province granted Apache an
exploration permit for CCyB Block 17B in the Cuyo Basin,
which increased our Argentine acreage by 34 percent. Apache
is currently awaiting Mendoza Province’s approval for the
extension of CCyB Block 17A, which is anticipated in the
first half of 2010. Together the two Mendoza Province blocks
comprise about 1.2 million acres. Approximately
505 square kilometers of
3-D
seismic
is scheduled to be acquired in 2010 using new cable-less
technology, the first time this technology has been used in
Argentina. A drilling campaign in the Cuyo Basin is also
scheduled to commence in mid-2010. With the addition of the
Mendoza acreage, Apache will hold oil and gas assets in three of
the main Argentine hydrocarbon basins: Neuquén, Austral and
Cuyo.
In March 2009 the Province of Neuquén and Apache reached
agreement 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 Apache’s total output in Argentina.
Activity during 2009 on our Tierra del Fuego assets included
nine discoveries, several facility projects and a fracture
stimulation campaign involving 10 wells. Future investment
by Apache in the Tierra del Fuego Province will be significantly
influenced by the probability of obtaining the Province’s
agreement to an extension of the present concession deadlines,
which are scheduled to expire in 2016 and 2017.
In 2009 our Argentina region produced 16.6 MMboe, drilled
29.6 net wells (32 gross) and performed 57 additional
capital projects. These programs added an estimated
14.4 MMboe in reserves and bring our reserves in Argentina
to an estimated 119.0 MMboe at December 31, 2009, or
five percent of our estimated worldwide total.
13
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During 2010 the region plans to invest approximately
$250 million for drilling, recompletion projects,
development projects, equipment upgrades, production enhancement
projects and seismic acquisition.
Marketing
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 2009 we realized an average price of $1.07 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 2009. Our overall average realized price for 2009 was
$1.96 per Mcf, 22 percent higher than 2008 average realized
prices ($1.61 per Mcf) and 68 percent higher than 2007
average realized prices ($1.17 per Mcf).
Taxes on exported oil effectively limit 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, 2009
oil prices realized from our Neuquén Basin production
averaged $44.09 per barrel, compared to $54.43 per barrel from
our Tierra del Fuego oil production.
Apache realized an additional $6 million of oil revenues in
2009 from benefits generated by the government’s Oil Plus
Program. This program rewarded participants that increased oil
production and reserves during 2008 and 2009. A further
$2 million of benefit was realized in January 2010.
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. Two of the wells reached total depth by
year-end 2009, with drilling completed on the third well in
early 2010. Currently a completion rig is conducting testing and
completion efforts on the three wells. During 2010 we plan to
invest approximately $25 million to $35 million for
drilling and seismic acquisition.
Major
Customers
In 2009 purchases by Shell accounted for 18 percent of the
Company’s worldwide oil and gas production revenues.
Subsequent
Events
Kitimat
LNG Terminal
On January 13, 2010, Apache announced that its Apache
Canada Ltd. subsidiary has agreed to acquire 51 percent of
Kitimat LNG Inc.’s proposed LNG export terminal in British
Columbia. Apache also reserved 51 percent of gas throughput
capacity in the terminal.
The proposed Kitimat project, located at Bish Cove near the Port
of Kitimat about 405 miles north of Vancouver, has planned
capacity of about
700 MMcf/d,
or five million metric tons of LNG per year. Preliminary gross
construction cost estimates of C$3 billion will be refined
at the conclusion of FEED. The project is projected to employ an
estimated 1,500 people during construction and 100 on a
permanent basis.
Kitimat is designed to be linked to the pipeline system
servicing Western Canada’s natural gas producing regions
via the proposed Pacific Trail Pipelines, a C$1.1 billion
project. In association with our acquisition of interest in the
Kitimat project, we also acquired a 25.5-percent interest in the
proposed pipeline and 350 MMcf/d of capacity rights.
2010
Performance Program
To provide long-term incentives for Apache employees to deliver
competitive returns to our stockholders, in January 2010 the
Company’s Board of Directors approved the 2010 Performance
Program, pursuant to the 2007
14
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Omnibus Equity Compensation Plan. Eligible employees received an
initial conditional restricted stock unit award of
541,440 units, with the ultimate number of restricted stock
units to be awarded, if any, 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 Company’s Board of Directors
also approved a one-time restricted stock unit award of
502,470 shares to eligible Apache employees, with one-third
of the units granted immediately vesting and an additional
one-third vesting on each of the first and second anniversaries
of the grant date.
Drilling
Statistics
Worldwide in 2009 we participated in drilling 610 gross
wells, with 558 (91 percent) completed as producers. We
also performed nearly 2,100 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: 12 in the U.S. (8.1 net); 5
in Canada (3.6 net); 14 in Egypt (13.0 net); 9 in Australia (3.1
net); 2 in the North Sea (1.9 net); and 2 in Argentina (2 net).
15
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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 | ||||||||||||||||||||||||||||
|
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 | |||||||||||||||||||||||||||
|
2007
|
||||||||||||||||||||||||||||||||||||
|
United States
|
3.0 | 3.1 | 6.1 | 264.9 | 16.5 | 281.4 | 267.9 | 19.6 | 287.5 | |||||||||||||||||||||||||||
|
Canada
|
9.5 | 15.5 | 25.0 | 206.0 | 35.4 | 241.4 | 215.5 | 50.9 | 266.4 | |||||||||||||||||||||||||||
|
Egypt
|
10.7 | 13.0 | 23.7 | 144.3 | 14.8 | 159.1 | 155.0 | 27.8 | 182.8 | |||||||||||||||||||||||||||
|
Australia
|
3.8 | 7.2 | 11.0 | 2.7 | — | 2.7 | 6.5 | 7.2 | 13.7 | |||||||||||||||||||||||||||
|
North Sea
|
— | 2.5 | 2.5 | 4.9 | 6.8 | 11.7 | 4.9 | 9.3 | 14.2 | |||||||||||||||||||||||||||
|
Argentina
|
2.0 | — | 2.0 | 80.8 | 2.0 | 82.8 | 82.8 | 2.0 | 84.8 | |||||||||||||||||||||||||||
|
Total
|
29.0 | 41.3 | 70.3 | 703.6 | 75.5 | 779.1 | 732.6 | 116.8 | 849.4 | |||||||||||||||||||||||||||
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, 2009, is set forth below:
| Gas | Oil | Total | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
|
Gulf Coast
|
830 | 655 | 967 | 712 | 1,797 | 1,367 | ||||||||||||||||||
|
Central
|
3,350 | 1,765 | 7,690 | 5,358 | 11,040 | 7,123 | ||||||||||||||||||
|
Canada
|
8,355 | 7,373 | 2,215 | 982 | 10,570 | 8,355 | ||||||||||||||||||
|
Egypt
|
45 | 45 | 660 | 640 | 705 | 685 | ||||||||||||||||||
|
Australia
|
12 | 8 | 32 | 20 | 44 | 28 | ||||||||||||||||||
|
North Sea
|
— | — | 74 | 72 | 74 | 72 | ||||||||||||||||||
|
Argentina
|
410 | 372 | 550 | 473 | 960 | 845 | ||||||||||||||||||
|
Total
|
13,002 | 10,218 | 12,188 | 8,257 | 25,190 | 18,475 | ||||||||||||||||||
16
Table of Contents
Production,
Pricing and Lease Operating Cost Data
The following table describes, for each of the last three fiscal
years, oil, natural gas liquids (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 |
Operating Cost per
|
Average Sales Price | ||||||||||||||||||||||||||
| Year Ended December 31, | Oil | NGLs | Gas | Boe | Oil | NGLs | Gas | |||||||||||||||||||||
| (Mbbls) | (Mbbls) | (MMcf) | (Per bbl) | (Per bbl) | (Per Mcf) | |||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||
|
United States
|
32,534 | 2,239 | 243,121 | $ | 10.59 | $ | 59.06 | $ | 33.02 | $ | 4.34 | |||||||||||||||||
|
Canada
|
5,543 | 763 | 131,121 | 11.46 | 56.16 | 25.54 | 4.17 | |||||||||||||||||||||
|
Egypt
|
33,631 | — | 132,355 | 5.17 | 61.34 | — | 3.70 | |||||||||||||||||||||
|
Australia
|
3,569 | — | 67,020 | 6.84 | 64.42 | — | 1.99 | |||||||||||||||||||||
|
North Sea
|
22,259 | — | 987 | 8.19 | 60.91 | — | 13.15 | |||||||||||||||||||||
|
Argentina
|
4,199 | 1,183 | 67,363 | 6.78 | 49.42 | 18.76 | 1.96 | |||||||||||||||||||||
|
Total
|
101,735 | 4,185 | 641,967 | $ | 8.48 | $ | 59.85 | $ | 27.63 | $ | 3.69 | |||||||||||||||||
|
2008
|
||||||||||||||||||||||||||||
|
United States
|
32,866 | 2,191 | 248,835 | $ | 12.62 | $ | 83.70 | $ | 58.62 | $ | 8.86 | |||||||||||||||||
|
Canada
|
6,278 | 760 | 129,099 | 14.00 | 93.53 | 49.33 | 7.94 | |||||||||||||||||||||
|
Egypt
|
24,431 | — | 96,518 | 6.47 | 91.37 | — | 5.25 | |||||||||||||||||||||
|
Australia
|
3,019 | — | 45,019 | 9.85 | 91.78 | — | 2.10 | |||||||||||||||||||||
|
North Sea
|
21,775 | — | 965 | 10.00 | 95.76 | — | 18.78 | |||||||||||||||||||||
|
Argentina
|
4,542 | 1,056 | 71,609 | 6.58 | 49.46 | 37.83 | 1.61 | |||||||||||||||||||||
|
Total
|
92,911 | 4,007 | 592,045 | $ | 10.56 | $ | 87.80 | $ | 51.38 | $ | 6.70 | |||||||||||||||||
|
2007
|
||||||||||||||||||||||||||||
|
United States
|
33,127 | 2,811 | 280,903 | $ | 10.55 | $ | 66.48 | $ | 45.24 | $ | 7.04 | |||||||||||||||||
|
Canada
|
6,846 | 820 | 141,697 | 12.36 | 68.29 | 40.55 | 6.30 | |||||||||||||||||||||
|
Egypt
|
22,168 | — | 87,883 | 5.16 | 72.51 | — | 4.60 | |||||||||||||||||||||
|
Australia
|
5,029 | — | 71,149 | 4.81 | 79.79 | — | 1.89 | |||||||||||||||||||||
|
North Sea
|
19,576 | — | 705 | 10.61 | 70.93 | — | 15.03 | |||||||||||||||||||||
|
Argentina
|
4,175 | 1,022 | 73,330 | 4.81 | 45.99 | 37.78 | 1.17 | |||||||||||||||||||||
|
Total
|
90,921 | 4,653 | 655,667 | $ | 8.90 | $ | 68.84 | $ | 42.78 | $ | 5.34 | |||||||||||||||||
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
|
2,133,890 | 1,347,842 | 2,854,176 | 1,762,757 | ||||||||||||
|
Canada
|
2,231,460 | 1,782,795 | 3,335,057 | 2,639,663 | ||||||||||||
|
Egypt
|
9,797,481 | 6,336,803 | 1,313,280 | 1,208,331 | ||||||||||||
|
Australia
|
5,843,110 | 3,886,650 | 744,776 | 402,500 | ||||||||||||
|
North Sea
|
341,195 | 237,380 | 41,019 | 39,846 | ||||||||||||
|
Argentina
|
2,889,000 | 2,610,000 | 259,000 | 194,000 | ||||||||||||
|
Chile
|
1,203,608 | 1,034,841 | — | — | ||||||||||||
|
Total
|
24,439,744 | 17,236,311 | 8,547,308 | 6,247,097 | ||||||||||||
17
Table of Contents
As of December 31, 2009, we had 2,948,251, 2,941,882 and
928,515 net acres scheduled to expire by December 31,
2010, 2011 and 2012, 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 expect a significant portion of our net acreage
position to expire before such actions occur.
As of December 31, 2009, 78 percent of U.S. net
undeveloped acreage and 44 percent of Canadian undeveloped
acreage was held by production.
Estimated
Proved Reserves and Future Net Cash Flows
In January 2009 the SEC issued Release
No. 33-8995,
“Modernization of Oil and Gas Reporting” (Release
33-8995),
amending oil and gas reporting requirements under
Rule 4-10
of
Regulation S-X
and Industry Guide 2 in
Regulation S-K
and bringing full-cost accounting rules into alignment with the
revised disclosure requirements. 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.
In January 2010 the Financial Accounting Standards Board (FASB)
issued Accounting Standards Update (ASU)
No. 2010-03
,
“Oil and Gas Reserve Estimation and Disclosures”
(ASU
2010-03),
which amends Accounting Standards Codification (ASC) Topic 932,
“Extractive Industries — Oil and Gas” to
align the guidance with the changes made by the SEC. The Company
adopted Release
33-8995
and
the amendments to ASC Topic 932 resulting from ASU
2010-03
(collectively, the Modernization Rules) effective
December 31, 2009.
Proved oil and gas reserves are the estimated quantities of
natural gas, crude oil, condensate and NGL’s 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 country’s 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.
Proved undeveloped (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.
18
Table of Contents
The following table shows proved oil, NGL and gas reserves as of
December 31, 2009, based on average commodity prices in
effect on the first day of each month in 2009, held flat for the
life of the production, except where future oil and gas sales
are covered by physical contract terms.
| Oil | NGL | Gas | Total | |||||||||||||
| (MMbbls) | (MMbbls) | (MMcf) | (MMboe) | |||||||||||||
|
Proved Developed:
|
||||||||||||||||
|
United States
|
344 | 29 | 1,785 | 671 | ||||||||||||
|
Canada
|
79 | 10 | 1,436 | 329 | ||||||||||||
|
Egypt
|
98 | — | 838 | 237 | ||||||||||||
|
Australia
|
33 | 1 | 700 | 151 | ||||||||||||
|
North Sea
|
142 | — | 5 | 143 | ||||||||||||
|
Argentina
|
19 | 7 | 473 | 105 | ||||||||||||
|
Proved Undeveloped:
|
||||||||||||||||
|
United States
|
144 | 6 | 653 | 260 | ||||||||||||
|
Canada
|
56 | 1 | 869 | 202 | ||||||||||||
|
Egypt
|
18 | — | 321 | 71 | ||||||||||||
|
Australia
|
44 | — | 662 | 154 | ||||||||||||
|
North Sea
|
30 | — | — | 30 | ||||||||||||
|
Argentina
|
5 | 1 | 54 | 14 | ||||||||||||
|
TOTAL PROVED
|
1,012 | 55 | 7,796 | 2,367 | ||||||||||||
As of December 31, 2009, Apache had total estimated proved
reserves of 1,067 MMbbls of crude oil, condensate and NGLs
and 7.8 Tcf of natural gas. Combined, these total estimated
proved reserves are the energy equivalent of 2.4 billion
barrels of oil or 14.2 Tcf of natural gas. As of
December 31, 2009, the Company’s proved developed
reserves totaled 1,636 MMboe, and estimated PUD reserves
totaled 731 MMboe, or approximately 31 percent of
worldwide total proved reserves. Apache has elected not to
disclose probable or possible reserves in this filing.
The Company’s estimates of proved reserves, proved
developed reserves and proved undeveloped reserves as of
December 31, 2009, 2008, 2007 and 2006, changes in
estimated proved reserves during the last three years, and
estimates of future net cash flows from proved reserves are
contained in Note 13 — 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, 2009,
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
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, and 2007, were estimated
using commodity prices in effect at the end of those years, in
accordance with the SEC guidelines in effect prior to the
issuance of the Modernization Rules.
Proved
Undeveloped Reserves
The Company’s total estimated proved undeveloped reserves
of 731 MMboe as of December 31, 2009, increased by
54 MMboe over the 677 MMboe of PUD reserves estimated
at the end of 2008. During the year, Apache converted
39 MMboe of proved undeveloped reserves to proved developed
reserves through development drilling activity. In North America
we converted 22 MMboe with the remaining 17 MMboe in
our international areas.
During the year a total of $760 million was spent on
projects associated with reserves that were carried as PUD
reserves at the end of 2008. Not all of those expenditures
resulted in a conversion from proved undeveloped to proved
developed reserves during the year. We spent $264 million
on PUD reserve development activity in North America and
$496 million in the international areas, including
$230 million in Australia where the reserves for those
projects will be converted to developed in future years.
19
Table of Contents
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. As additional geoscience, engineering and economic
data are obtained, proved reserve estimates are much more likely
to increase or remain constant than to decrease. These estimates
are reviewed throughout the year and revised either upward or
downward, as warranted.
Apache’s 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 Apache’s 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 Apache’s
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.
Apache’s Executive Vice President of Corporate Reservoir
Engineering, W. Kregg Olson, 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. Mr. Olson is a graduate of
Texas A&M University with a Bachelor of Science degree in
Petroleum Engineering. He has over 29 years of industry
experience, with the last 25 years focused on reservoir
engineering. He is a member of the Society of Petroleum
Engineers and is a Registered Professional Engineer in the state
of Oklahoma. Mr. Olson has held positions of increasing
responsibility within Apache’s corporate reservoir
engineering department since joining the company in 1992.
The estimate of reserves disclosed in this annual report on
Form 10-K
is prepared by the Company’s 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. These properties represented all material
fields, and over 85 percent of international properties and
new wells drilled during the year. During 2009, 2008, and 2007,
Ryder Scott’s review covered 79, 82 and 77 percent of
the Company’s worldwide estimated reserves value,
respectively. We have filed Ryder Scott’s independent
report as an exhibit to this
Form 10-K.
Ryder Scott opined that the overall proved reserves for the
reviewed properties as estimated by the Company are, in the
aggregate, reasonable, prepared in accordance with generally
accepted petroleum engineering and evaluation principles and
conform to the SEC’s definition of proved reserves as set
forth in
Rule 210.4-10(a)
of
Regulation S-X.
Ryder Scott has informed the Company that the tests and
procedures used during its reserves audit conform to the
Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information approved by the Society of Petroleum
Engineers. Paragraph 2.2(f) of the Standards Pertaining to
the Estimating and Auditing of Oil and Gas Reserves Information
defines a reserves audit as the process of reviewing certain of
the pertinent facts interpreted and assumptions made that have
resulted in an estimate of reserves prepared by others and the
rendering of an opinion about (1) the appropriateness of
the methodologies employed, (2) the adequacy and quality of
the data relied upon, (3) the depth and thoroughness of the
reserves estimation process, (4) the classification of
reserves appropriate to the relevant definitions used, and
(5) the reasonableness of the estimated reserve quantities.
A reserve audit is not the same as a financial audit and is less
rigorous in nature than an independent reserve report where the
independent reserve engineer determines the reserves on his or
her own.
Employees
On December 31, 2009, we had 3,452 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 2009 we maintained regional exploration
and/or
production offices in
20
Table of Contents
Tulsa, Oklahoma; Houston, 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
Company’s obligations under its office leases, please see
Part II, Item 7 — Management’s
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.
| ITEM 1A. | RISK FACTORS |
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 recession that began in 2008 and extended into 2009.
Growth has resumed but is modest. 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 we have experienced in recent years. In
addition, more volatility may occur before a sustainable 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.
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 2009 ranged from a
high of $81.37 per barrel to a low of $33.98 per barrel. The
NYMEX daily settlement price for the prompt month natural gas
contract in 2009 ranged from a high of $6.07 per MMBtu to a low
of $2.51 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:
| • | worldwide and domestic supplies of crude oil and natural gas; | |
| • | actions taken by foreign oil and gas producing nations; |
21
Table of Contents
| • | political conditions and events (including instability or armed conflict) in crude oil or natural gas producing regions; | |
| • | the level of global crude oil and natural gas inventories; | |
| • | the price and level of imported foreign crude oil and natural gas; | |
| • | the price and availability of alternative fuels, including coal and biofuels; | |
| • | the availability of pipeline capacity and infrastructure; | |
| • | the availability of crude oil transportation and refining capacity; | |
| • | weather conditions; | |
| • | electricity generation; | |
| • | domestic and foreign governmental regulations and taxes; and | |
| • | the overall economic environment. |
Significant declines in crude oil and natural gas prices for an
extended period may have the following effects on our business:
| • | limiting our financial condition, liquidity, and/or ability to fund planned capital expenditures and operations; | |
| • | reducing the amount of crude oil and natural gas that we can produce economically; | |
| • | causing us to delay or postpone some of our capital projects; | |
| • | reducing our revenues, operating income and cash flows; | |
| • | limiting our access to sources of capital, such as equity and long-term debt; | |
| • | a reduction in the carrying value of our crude oil and natural gas properties; or | |
| • | a reduction in the carrying value of goodwill. |
We recorded asset impairment charges during 2009. If commodity
prices decline during 2010, 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 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.
22
Table of Contents
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:
| • | our production falls short of the hedged volumes; | |
| • | there is a widening of price-basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; | |
| • | the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; or | |
| • | a sudden unexpected event materially impacts oil and natural gas prices. |
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 affect their ability to fulfill
their existing obligations to us and their willingness to enter
into future transactions with us. We have exposure to these
financial institutions in the form of derivative transactions in
connection with our hedges. We also maintain insurance policies
with insurance companies to protect us against certain risks
inherent in our business. 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
lender’s 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, reserve mix and
commodity pricing levels could also be considered by the rating
agencies. Apache’s senior unsecured long-term debt is
currently rated A3 by Moody’s, A- by Standard &
Poor’s and A- by Fitch. The Company has received short-term
debt ratings for its commercial paper program of
P-2
from
Moody’s,
A-2
from
Standard & Poor’s and F2 from Fitch. In September
2009 Fitch downgraded Apache’s senior unsecured long-term
debt and short-term debt from A and F1 to A- and F2,
respectively. The current outlook at all three rating agencies
is stable. A further 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 in certain circumstances.
Market
conditions may restrict our ability to obtain funds for future
development and working capital needs, which may limit our
financial flexibility.
During 2009 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.
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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.
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, 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:
| • | unexpected drilling conditions; | |
| • | pressure or irregularities in formations; | |
| • | equipment failures or accidents; | |
| • | fires, explosions, blowouts and surface cratering; | |
| • | marine risks such as capsizing, collisions and hurricanes; | |
| • | other adverse weather conditions; and | |
| • | increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment. |
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
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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 associated 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
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.
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 SEC’s 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:
| • | historical production from the area compared with production from other areas; | |
| • | the assumed effects of regulations by governmental agencies, including the impact of the SEC’s new oil and gas company reserves reporting requirements; | |
| • | assumptions concerning future crude oil and natural gas prices; | |
| • | future operating costs; | |
| • | severance and excise taxes; | |
| • | development costs; and | |
| • | workover and remediation costs. |
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
25
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capital, drilling and production costs, availability of drilling
services and equipment, gathering system and pipeline
transportation constraints and regulatory approvals.
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 affect 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, Canada, the United Kingdom and the
United States, 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 2009, only two of the jurisdictions in
which the Company has operations, Alberta, 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 Apache’s
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
Company’s assets or operations. However, any increase in
severe weather could have a material adverse effect on our
assets and operations.
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The
proposed U.S. federal budget for fiscal year 2011 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 1, 2010, the Office of Management and Budget
released a summary of the proposed U.S. federal budget for
fiscal year 2011. 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 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 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 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.
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 2009
production was outside North America and approximately
38 percent of our estimated proved oil and gas reserves on
December 31, 2009 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:
| • | general strikes and civil unrest; | |
| • | the risk of war, acts of terrorism, expropriation and resource nationalization, forced renegotiation or modification of existing contracts; | |
| • | import and export regulations; | |
| • | taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions; | |
| • | price control; | |
| • | transportation regulations and tariffs; | |
| • | constrained natural gas markets dependent on demand in a single or limited geographical area; | |
| • | exchange controls, currency fluctuations, devaluation or other activities that limit or disrupt markets and restrict payments or the movement of funds; | |
| • | laws and policies of the United States affecting foreign trade, including trade sanctions; | |
| • | 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; | |
| • | 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 |
27
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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. |
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
management’s 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.
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 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. | UNRESOLVED SEC STAFF COMMENTS |
As of December 31, 2009, we did not have any unresolved
comments from the SEC staff that were received 180 or more days
prior to year-end.
| ITEM 3. | LEGAL PROCEEDINGS |
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.
| ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
No matters were submitted to a vote of our security holders
during the most recently ended fiscal quarter.
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Table of Contents
PART II
| ITEM 5. | MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS |
During 2009 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 2009 and 2008. 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.
| 2009 | 2008 | |||||||||||||||||||||||||||||||
| Price Range | Dividends Per Share | Price Range | Dividends Per Share | |||||||||||||||||||||||||||||
| High | Low | Declared | Paid | High | Low | Declared | Paid | |||||||||||||||||||||||||
|
First Quarter
|
$ | 88.07 | $ | 51.03 | $ | .15 | $ | .15 | $ | 122.34 | $ | 84.52 | $ | .25 | $ | .25 | ||||||||||||||||
|
Second Quarter
|
87.04 | 61.60 | .15 | .15 | 149.23 | 117.65 | .15 | 15 | ||||||||||||||||||||||||
|
Third Quarter
|
95.77 | 65.02 | .15 | .15 | 145.00 | 94.82 | .15 | .15 | ||||||||||||||||||||||||
|
Fourth Quarter
|
106.46 | 88.06 | .15 | .15 | 103.17 | 57.11 | .15 | .15 | ||||||||||||||||||||||||
The closing price of our common stock, as reported on the New
York Stock Exchange Composite Transactions Reporting System for
January 29, 2010 (last trading day of the month), was
$98.77 per share. As of January 31, 2010, there were
336,550,234 shares of our common stock outstanding held by
approximately 5,800 stockholders of record and approximately
442,000 beneficial owners.
We have paid cash dividends on our common stock for 45
consecutive years through December 31, 2009. 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 Company’s 2010 annual meeting of
stockholders, which is incorporated herein by reference.
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The following stock price performance graph is intended to allow
review of stockholder returns, expressed in terms of the
appreciation of the Company’s 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 Company’s common stock with the
cumulative total return of the Standard & Poor’s
Composite 500 Stock Index and of the Dow Jones
U.S. Exploration & Production Index (formerly Dow
Jones Secondary Oil Stock Index) from December 31, 2004,
through December 31, 2009.
COMPARISON
OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Apache Corporation, S&P 500 Index
and the Dow Jones US Exploration & Production
Index
| * |
$100 invested on 12/31/04 in stock including reinvestment of
dividends.
Fiscal year ending December 31. |
| 2004 | 2005 | 2006 | 2007 | 2008 | 2009 | |||||||||||||||||||||||||
|
Apache Corporation
|
$ | 100.00 | $ | 136.28 | $ | 133.14 | $ | 216.91 | $ | 151.34 | $ | 211.14 | ||||||||||||||||||
|
S & P’s Composite 500 Stock Index
|
100.00 | 104.91 | 121.48 | 128.16 | 80.74 | 102.11 | ||||||||||||||||||||||||
|
DJ US Expl & Prod Index
|
100.00 | 165.32 | 174.20 | 250.27 | 149.86 | 210.65 | ||||||||||||||||||||||||
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Table of Contents
| ITEM 6. | SELECTED FINANCIAL DATA |
The following table sets forth selected financial data of the
Company and its consolidated subsidiaries over the five-year
period ended December 31, 2009, which information has been
derived from the Company’s audited financial statements.
This information should be read in connection with, and is
qualified in its entirety by, the more detailed information in
the Company’s 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 Company’s 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 Company’s U.S.,
U.K. North Sea, Canadian and Argentine proved oil and gas
properties as of December 31, 2008.
| As of or for the Year Ended December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||||
| (In thousands, except per share amounts) | ||||||||||||||||||||
|
Income Statement Data
|
||||||||||||||||||||
|
Total revenues
|
$ | 8,614,826 | $ | 12,389,750 | $ | 9,999,752 | $ | 8,309,131 | $ | 7,584,244 | ||||||||||
|
Income (loss) attributable to common stock
|
(291,692 | ) | 706,274 | 2,806,678 | 2,546,771 | 2,618,050 | ||||||||||||||
|
Net income (loss) per common share:
|
||||||||||||||||||||
|
Basic
|
(.87 | ) | 2.11 | 8.45 | 7.72 | 7.96 | ||||||||||||||
|
Diluted
|
(.87 | ) | 2.09 | 8.39 | 7.64 | 7.84 | ||||||||||||||
|
Cash dividends declared per common share
|
.60 | .70 | .60 | .50 | .36 | |||||||||||||||
|
Balance Sheet Data
|
||||||||||||||||||||
|
Total assets
|
$ | 28,185,743 | $ | 29,186,485 | $ | 28,634,651 | $ | 24,308,175 | $ | 19,271,796 | ||||||||||
|
Long-term debt
|
4,950,390 | 4,808,975 | 4,011,605 | 2,019,831 | 2,191,954 | |||||||||||||||
|
Shareholders’ equity
|
15,778,621 | 16,508,721 | 15,377,979 | 13,191,053 | 10,541,215 | |||||||||||||||
|
Common shares outstanding
|
336,437 | 334,710 | 332,927 | 330,737 | 330,121 | |||||||||||||||
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.
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Table of Contents
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Apache Corporation, a Delaware corporation formed in 1954, is an
independent energy company engaged in worldwide crude oil,
natural gas and NGL exploration and production. In North
America, our exploration and production operations are focused
in the Gulf of Mexico, the Gulf Coast, East Texas, the Permian
Basin, the Anadarko Basin and the Western Sedimentary Basin of
Canada. Outside of North America, we have exploration and
production operations onshore Egypt, offshore Western Australia,
offshore the United Kingdom (U.K.) in the North Sea (North Sea),
and onshore Argentina. We also have exploration interests on the
Chilean side of the island of Tierra del Fuego.
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
Apache’s mission is to grow a profitable upstream oil and
gas company for the long-term benefit of our shareholders.
Apache’s long-term perspective has many dimensions, with
the following core principles:
| • | Own a balanced portfolio of core assets; | |
| • | Maintain financial flexibility and a strong balance sheet; and | |
| • | Optimize rates of return, earnings and cash flow. |
Throughout the cycles of our industry, these strategies have
underpinned our ability to deliver 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 24 years and production 29 out of the past
31 years, a testament to our consistency over the long-term.
These strategies have served us well in the past and should
continue to serve us well going forward. However, we also
believe several long-term trends across the globe will have a
tremendous impact on supply and demand for fuel and on
Apache’s business model in the years ahead.
| • | Demand for fuel continues to grow in many parts of the developing world, where billions of people are seeking to move up the economic ladder. | |
| • | A new psychology of scarcity is driving competition for resources around the world and testing many long-held assumptions and relationships. The world will need all sources of energy — including wind, solar and other alternatives — to keep up with long-term demand growth. | |
| • | In North America, recent improvements in horizontal drilling and completion technology have transformed the natural gas market, opening up a 100-year resource with the potential to improve U.S. energy security, create jobs and help achieve environmental and climate change goals. |
We believe Apache’s evolution from a domestic driller and
producer to an independent global exploration and production
company, coupled with our sense of urgency, discipline,
innovation and spirit, positions us well to take advantage of
these impending trends. Our current production base provides the
cash flow required for us to seek out larger exploration targets
while developing our discoveries, including Qasr in Egypt,
Julimar in Australia and the Horn River Basin of British
Columbia.
As we head into 2010, we anticipate that higher production will
generate adequate cash flow to support a higher activity level
compared to 2009. Two oil developments in Australia —
Van Gogh and Pyrenees — will contribute significant
volumes in 2010. Also, gas production in the Horn River Basin
shale play will begin ramping up in 2010 as Apache’s teams
apply technological innovations to complete wells more quickly
and at lower cost.
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However, while we are comfortable that our $2 billion of
cash on hand at year-end and the additional liquidity available
from our credit facilities will provide ample flexibility to
pursue additional exploration activity or opportunistic,
value-adding acquisitions, lingering issues in the credit
markets clearly demonstrate that any detectable economic
recovery is fragile at best. Therefore, we will continue to
manage drilling and development capital spending in line with
available cash flow.
Financial
and Operating Results
The dramatic decline in oil and gas prices and global financial
crisis that began in 2008 provided the backdrop for our primary
objective in 2009: living within our cash flow to preserve
financial flexibility. Although we curtailed activity to achieve
this objective, Apache delivered record annual average daily
production — up nine percent from 2008 — and
added slightly more reserves, excluding revisions, than we
produced.
The decline in oil and gas prices impacted Apache’s 2009
financial results, requiring us to reduce the carrying value of
oil and gas properties and resulting in a $1.98-billion non-cash
charge to earnings during the first quarter. However, with
rebounding oil prices and higher production, earnings
strengthened throughout the remainder of the year.
To ensure we lived within cash flow, we reduced 2009 activity
and investments to $4.1 billion, 39 percent below 2008
levels. Despite curtailed capital spending, we moved forward on
several large development projects, pursued exploration
opportunities resulting in several important new discoveries,
increased production nine percent to a record 583,328 boe/d and
generated $4.2 billion in net cash provided by operating
activities. In addition, we maintained our strong balance sheet
and ample liquidity levels, exiting 2009 with a
debt-to-capitalization
ratio of 24 percent, just over $2 billion of cash and
$2.3 billion in available committed borrowing capacity. We
also believe our single-A debt ratings provide a competitive
advantage in accessing capital.
For the year, Apache recorded a net loss of $292 million,
or $.87 per common diluted share, compared to 2008 net
income of $706 million, or $2.09 per common diluted share.
Apache’s 2009 reported adjusted earnings (1) , which
exclude certain items impacting the comparability of results,
were $1.98 billion or $5.59 per common diluted share, down
from $3.8 billion or $11.22 per common diluted share in the
prior year. We generated net cash provided by operating
activities totaling $4.2 billion, down from
$7.1 billion in 2008.
The following items impacted our 2009 earnings and cash flow as
compared to 2008:
| • | Record production of 583,328 boe/d, up nine percent from 2008; | |
| • | Average realized oil prices decreased 32 percent to $59.85 per bbl; | |
| • | Average realized gas prices decreased 45 percent to $3.69 per Mcf; | |
| • | A non-cash after-tax write-down of the carrying value of proved property of $1.98 billion in 2009 versus $3.6 billion in 2008 affected earnings; and | |
| • | Total operating expenses decreased $3.2 billion, or 28 percent, from 2008. |
(1) See
Results of Operations —
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.
Proposed
Climate Change Legislation
Management believes that climate change legislation globally is
undergoing a phase of significant evolution, and as a
consequence, the Company perceives an unusual lack of clarity
surrounding this issue. Furthermore, in the United States, the
Company is concerned that legislation will distort markets and
protect other energy sectors. The Company believes that natural
gas offers the most cost effective means to reduce greenhouse
gas (GHG) emissions rapidly and the Company is well positioned
to contribute to an overall increase of natural gas supply.
34
Table of Contents
Apache
Greenhouse Gas Emissions Reporting
Total gross GHG emissions from Apache operated properties
world-wide are calculated and reported to the Carbon Disclosure
Project (CDP) on a country-by-country basis using recognized
international protocols. Currently the CDP maintains a public
access website with Apache information for calendar year 2008.
Emissions for calendar year 2009 are due to be reported to CDP
by May for posting later in 2010. Readers are advised that
Apache GHG emissions values are not subject to the same rigorous
controls for accuracy and reliability as financial data found in
this filing, and that there are inherent limitations for
directly measuring GHG emissions from oil and gas production
facilities in general.
In addition, for required facilities, Apache GHG emissions are
reported to local and national authorities in Australia, Canada
and the United Kingdom following reporting standards specific to
each jurisdiction, and verified according to regulatory
requirements. For 2010, the United States Environmental
Protection Agency will require emissions reports covering some
of our largest fixed combustion facilities.
Operating
Highlights
Operational highlights for the year and growth drivers for 2010
and beyond are as follows:
Australia
During 2009 the Australia region restored operations and
increased capacity at the Varanus Island gas processing
facility, and it continued to lay the foundation for future
growth by developing previously discovered fields that will come
on-line over the short, intermediate and long terms. Our Van
Gogh and Pyrenees discoveries (oil fields) commenced production
in the first quarter of 2010. In the intermediate-term, our
Halyard and Reindeer discoveries (gas fields) are scheduled to
begin producing in 2011. In the longer term, we will see
additional production from our Julimar, Macedon and Coniston
field discoveries, as discussed below.
Discoveries
expected to begin producing in 2010
| • | Van Gogh Discovery Development Drilling and installation of subsea production equipment were completed in 2009 at the Apache-operated Van Gogh field discovery. Limited production began in February 2010, with routine commissioning activities still being performed on the floating, production, storage, and offloading vessel (FPSO) servicing the field. | |
| • | Pyrenees Discovery Development Installation of subsea facilities at our Pyrenees field was completed in 2009. First oil production commenced ahead of schedule, on February 24, 2010. As planned, the wells will be drilled and brought on in phases, with half of the expected production volume ramping up over the next six months. |
Peak production from the Van Gogh and Pyrenees discoveries is
projected to reach a combined 40,000 b/d net to Apache.
Discoveries
expected to begin producing in 2011
| • | Halyard Discovery Development In April 2008 we drilled the Halyard-1 discovery well, which tested 68 MMcf/d. We currently plan to tie the field into the existing nearby East Spar gas facilities. First production is anticipated in 2011. | |
| • | Reindeer Discovery Development Our Reindeer field discovery will be produced through an onshore gas plant currently under construction, the Devil Creek gas plant. In 2009, we entered into a gas sales contract covering a portion of the field’s 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 second half of 2011 at prices higher than we have historically received in Western Australia. Apache owns a 55-percent interest in the field. The company is continuing to market its remaining net share in the Reindeer field. |
35
Table of Contents
Discoveries
expected to begin producing after 2011
| • | Julimar and Brunello Natural Gas Discoveries Our Julimar and Brunello natural gas discoveries will be produced through liquefied natural gas (LNG) facilities (discussed below). The LNG project, which is currently in front-end engineering and design (FEED), will convert the gas into LNG for sale on the world market. World LNG prices are typically tied to oil prices, and are currently higher than gas prices we have historically received in Western Australia. Our projected net sales would approximate 190 MMcf/d and 5,100 b/d with a projected 15-year production plateau when the multi-year project is complete and all the wells are producing. | |
| • | Wheatstone LNG Project In October 2009, Apache announced an agreement to become a foundation equity partner in Chevron’s Wheatstone LNG hub in Western Australia. Chevron, which has a 100-percent interest in the Wheatstone field, will operate the LNG facilities with a 75-percent interest. Apache will own 16.25 percent interest in the project and our partner in the Julimar and Brunello fields will own the remaining project interest. The Wheatstone project is targeting a final investment decision (FID) in 2011 and first sales from the facility are projected for 2015. Our net capital for the project is currently estimated to be $1.2 billion for upstream development of the Julimar and Brunello fields and $3.0 billion in the Wheatstone facilities. The investment will be funded as the multi-year project is developed. | |
| • | Macedon and Coniston Discoveries We have two contingent development opportunities that will be evaluated during 2010. The Macedon field is a gas discovery near our Pyrenees field which is currently being reviewed by the operator, BHP Billiton, for commercial development. Gas produced from Pyrenees will be reinjected into the Macedon field to reduce flaring and conserve those volumes for future production. The Coniston field is an oil accumulation near our Van Gogh field. Apache drilled 10 appraisal wells during the year and is evaluating a development plan to tie-back the field to the FPSO currently serving the Van Gogh field. |
Egypt
Notable successes during the year include:
2X
Project
| • | In June 2005, Apache and the Egyptian government set a goal to double gross equivalent production from Apache operated concessions by the end of 2010 (2X Project). At the time of the proposal, Apache’s gross operated equivalent production was approximately 163 Mboe/d. As we exited 2009, Egypt was over 90 percent of the way to reaching that goal. |
Double-digit
Growth in both oil and gas production
| • | Egypt’s gross gas production increased 26 percent, driven by exploration successes at our Khalda and Matruh concessions and from 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 pipeline allowed previously discovered wells in the Khalda Concession Qasr field to come online. The increased compression in the Northern Gas Pipeline also allowed increased throughput at the nearby Tarek plant and enabled us to begin producing previous discoveries at the Jade and Falcon fields in our Matruh concession. | |
| • | Egypt’s gross oil production increased 25 percent on exploration successes in numerous concessions, most notably East Bahariya Extension, South Umbarka, Matruh, NEAG Extension and Khalda. Waterflood projects and increased condensate from additional Qasr gas flowing through the new processing trains at Salam Gas Plant also contributed. | |
| • | Additional plant and pipeline capacity expansion will be required in the coming years to keep pace with the internally-generated discoveries described below. |
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Table of Contents
Development,
Exploration and Appraisal Activity
| • | Phiops Field Discovery Kalabsha Concession — Current production from the Phiops field, initially discovered in late 2008, is approximately 8,100 b/d gross, with two of four completed wells shut-in due to facility constraints. The Phiops field is the largest of five fields discovered in the Faghur Basin of the Western Desert since 2006 by Apache through its joint venture partner, Khalda Petroleum Company. We expect to increase production to 20,000 gross barrels per day when additional infrastructure is completed by mid-2010. To allow for future production growth, a second phase of infrastructure expansion to 40,000 b/d, is targeted for completion by the end of the third quarter of 2010. In addition, gas capacity of 38 MMcf/d is slated for mid-2011. Further exploration, appraisal and development activity in the concession is planned for 2010. | |
| • | Concession Extensions Amendments to extend our Siwa, Sallum, and West Ghazalat exploration concessions for an additional three years (to July 27, 2013) were approved by the Egyptian Parliament in June 2009. These concessions encompass 3.8 million gross acres, which Apache operates with a 50-percent contractor interest. Seismic acquisition and early exploration drilling is planned for 2010. Additionally, we finalized extension of the Khalda Offset and East Bahariya concessions in the Western Desert. At Khalda Offset, the exploration phase is extended until July 2016. Apache has a 100-percent contractor interest in this concession, which covers 909,000 acres. The East Bahariya concession exploration phase was extended through July 2012. Apache has a 100-percent contractor interest in this concession, which encompasses 674,000 acres. | |
| • | North Tarek Concession On April 30, 2009, we announced the NTRK-C-1X well, our first discovery in this concession along the Mediterranean coast, tested at a rate of 3,489 b/d and 5 MMcf/d. Additional drilling is planned for 2010. | |
| • | Shushan C Concession Hydra Field — Apache has had numerous exploration successes on this concession and is in the process of negotiating a Gas Sales Agreement with Egyptian General Petroleum Corporation (EGPC). When the agreement is completed, we will file to establish a development lease. The most recent discovery, the Hydra-5X appraisal well, tested 21 MMcf/d and 3,744 b/d. This well follows Apache’s Hydra-1X discovery drilled in 2008 which test-flowed 76.6 MMcf/d and 2,813 b/d. | |
| • | Other Discoveries During 2009 we had three additional discoveries in Egypt’s Western Desert that tested an aggregate 80 MMcf/d and 5,909 b/d. The Sultan-3X located on the Khalda Offset Concession test-flowed 5,021 b/d and 11 MMcf/d. The two other discoveries, the Adam-1X and the Maggie-1X, discovered new gas-condensate fields on the Matruh development lease north of the Sultan discovery. Apache has a 100-percent contractor interest in both concessions. Oil production from Sultan-3X began in the first quarter of 2009. |
North
America
Apache’s North American asset base, comprised of the
U.S. Central and Gulf Coast Regions along with Canada,
reflects the balanced portfolio approach that has long been one
of the Company’s greatest strengths. The Central Region
provided steady, predictable results with its high-quality
assets and large acreage base. The Gulf Coast Region delivered
solid production despite curtailment of capital spending. Also,
the region restored virtually all production shut-in by
hurricanes. Canada laid the foundation for future growth through
its shale-gas plays and Kitimat LNG acquisition. Operating
highlights for 2009 and future growth drivers for our North
American operations include the following:
U.S.
Central Region
| • | During the second quarter of 2009 we announced the acquisition of nine Permian Basin oil and gas fields with current net production of 3,500 barrels of oil equivalent per day from Marathon Oil Corporation for $187.4 million, subject to normal post-closing adjustments. These long-lived oil fields fit well with Apache’s existing properties in the Permian Basin, particularly in Lea County, N.M., and will provide us drilling opportunities for many years. The effective date of the transaction was January 1, 2009. |
37
Table of Contents
| • | In 2009 we drilled our first operated horizontal well in the Granite Wash play in Washita County, Oklahoma. The Hostetter #1-23H commenced production in September 2009 at 17 MMcf/d and 800 b/d and is currently producing 9.5 MMcf/d and 600 b/d. Apache owns a 72-percent working interest in the well. We have drilled extensively over the past decade in the Granite Wash, and as a result, we control approximately 200,000 gross acres in the play, mostly held-by-production. Hundreds of additional horizontal well locations have been identified across our acreage, extending opportunities for many years. In early 2010 we had three rigs in operation with plans to increase to at least five as we target drilling a minimum of 29 horizontal wells in the play during the year. |
U.S. Gulf
Coast Region
| • | In April 2009 we announced a key deepwater discovery at Ewing Banks Block 998 that test-flowed 4,254 b/d and 5.4 MMcf/d. The well will be connected to existing facilities, with first production projected for mid-year 2010. Apache owns a 50-percent interest in the property. | |
| • | In May 2009 production commenced from two deepwater discoveries in the Geauxpher field, located on Garden Banks Block 462. During the second half of 2009, the field produced an average of 91 MMcf/d gross. Apache generated the prospect and has a 40-percent working interest. | |
| • | At South Timbalier 287 (drilled from Apache’s South Timbalier 308 platform), the #A-8 well came online flowing 1,800 b/d. Apache has a 100-percent working interest in this well. | |
| • | At Ewing Banks 826, four successful wells were drilled as part of our redevelopment program. Initial production rates ranged from 500 b/d to 1,000 b/d per well. Apache has a 100-percent working interest in these wells. | |
| • | A relatively quiet hurricane season allowed the region to continue restoration of shut-in production in the Gulf of Mexico. We made considerable progress, and virtually all production shut-in by hurricanes has been restored. |
Canada
Unconventional gas opportunities in Canada are anticipated to
drive future growth of Apache’s Canadian region, moving
beyond conventional plays in Alberta, British Columbia and
Saskatchewan that have been the foundation of the region’s
activities for 15 years.
| • | Horn River Basin Shale Gas Play Apache continued development activity on its Horn River Basin shale-gas play in northeast British Columbia, where we have over 220,000 highly prospective net acres. During 2009 Apache and its joint interest partner drilled 41 horizontal wells. Four of these wells were completed and placed on production by year-end 2009 and were producing at a combined gross rate in excess of 19 MMcf/d. Apache commenced stimulating the 16 wells on its first operated development pad in the fourth quarter of 2009, with production scheduled for mid-2010. A total of 55 wells are planned for completion in 2010. Additionally, during the second quarter of 2009, a new dehydration and compressor facility and a new 42-mile 24-inch sales line, with capacity of over 700 MMcf/d, was commissioned that will allow us to flow gas to a third-party interconnect point when completed in 2010. | |
| • | Kitimat LNG Terminal The expected magnitude of the Horn River Basin resources and its remote location — far from most major North American markets — prompted Apache to seek alternative markets. In January 2010 we announced an agreement to acquire a 51-percent interest in Kitimat LNG, Inc’s. proposed LNG export terminal in British Columbia. We also reserved 51 percent of throughput capacity in the terminal. Planned plant capacity will be approximately 700 MMcf/d, or five million metric tons of LNG per day. This project has the potential to access new markets in the Asia-Pacific region and allow Apache to monetize gas from its Canadian region, including its interest in the Horn River Basin in northeast British Columbia. A final investment decision is expected in 2011, with the first LNG shipments projected for as early as 2014. Apache will become the operator of the project. Preliminary gross construction cost estimates, which will be refined upon completion of a FEED study, total C$3 billion. Kitimat is designed to be linked to the pipeline system servicing Western Canada’s natural gas producing regions via the proposed Pacific Trail |
38
Table of Contents
| Pipelines, a project with a current estimated gross cost of C$1.1 billion. In association with our acquisition of interest in the Kitimat project, we also acquired a 25.5-percent interest in the proposed pipeline and 350 MMcf/d of capacity rights. |
| • | Corridor Resources, Inc. Farm-in In December 2009, we entered into a farm-in agreement with Corridor Resources Inc. (Corridor) to appraise and potentially develop oil and natural gas resources in the province of New Brunswick, Canada. The initial 18-month program is intended to evaluate the commercial potential of natural gas development in the Frederick Brook formation and light oil development at a recent Caledonia oil discovery at a cost to Apache of not less than $25 million. Upon completion of this appraisal program, Apache will have earned a 50-percent working interest in the spacing units drilled. Apache will then have the option to participate in phase two of the program at a cost of not less than $100 million. Upon completion of this phase by March 31, 2013, Apache would earn a 50-percent interest in approximately 116,000 acres. |
North
Sea
Apache entered the North Sea in 2003 upon acquiring an
approximate 97-percent working interest in the Forties field
(Forties). Production increased two percent in 2009, as gains
from our drilling and workover programs more than offset
unplanned downtime to replace an original vintage spool section
at the end of the Bravo-Charlie infield pipeline, which lowered
production for the year by 2,690 boe/d.
In addition to an active year of drilling, we completed and made
significant progress on several important facility projects that
will benefit Forties in the years ahead. The Delta-Charlie
infield pipeline was replaced, bringing improved mechanical
integrity. We installed and commissioned a new power turbine on
Delta to support increasing field-water injection during 2010.
On the Charlie platform, we purchased equipment, cleared access
and began installing components late in 2009 for a new
high-pressure gas lift system that will be operational in early
2011. Work that began on the Echo platform several years ago to
replace the antiquated and unreliable controls system with a
modern version was fundamentally completed. The various facility
upgrade and improvement projects completed in recent years
resulted in a significant reduction in the number of occurrences
of unplanned downtime. In 2009 we had fewer events causing
unplanned downtime than we have experienced in any year since
acquiring the Forties field; 64 percent less than our
previous best year.
Argentina
Argentina announced several strategic agreements during 2009
that will improve the long-term viability of our investments.
Exploration
Activity
| • | On March 30, 2009, Apache announced that the Neuquén Province of Argentina agreed to extend the term of eight federal oil and gas concessions for 10 additional years. Neuquén operations provide about half of Apache’s total output in Argentina. The concessions encompass approximately 590,000 acres, including exploratory areas totaling 514,000 acres. In exchange for production that would have reverted to the Province beginning in six years and the right to explore for 10 additional years, Apache paid a bonus of approximately $23 million, increased the provincial royalty to 15 percent from 12 percent and will spend up to $320 million in future work programs over a 19-year period. |
Development
Activity
| • | During 2009 Apache received technical and commercial approval from the government of Argentina for four Gas Plus projects and technical approval for two more Gas Plus projects designed to encourage new supplies through development of tight sands and unconventional gas reserves. Under the Gas Plus program, Apache has the opportunity to supply 10 MMcf/d from fields in the Neuquén Province at a price of $4.10 per MMBtu beginning January 2010 for an initial one-year term. The Company also has a letter of intent for a contract to supply up to 50 MMcf/d from fields in the Neuquén and Rio Negro Provinces for $5.00 per MMBtu beginning January 2011. The gas supplying the Gas Plus program contracts is required to come from wells |
39
Table of Contents
| drilled in the projects’ approved fields and formations. We believe this type of program, coupled with changing market conditions, point to improving price realizations going forward. |
Chile
Exploration
Activity
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. Two of the wells reached total depth by
year-end 2009, with drilling completed on the third well in
early 2010. Currently a completion rig is conducting testing and
completion efforts on the three wells. During 2010 the region
will invest approximately $25 million to $35 million
for drilling and seismic acquisition.
Results
of Operations
Oil
and Gas Revenues, Production and Prices
| Revenues for the Year Ended December 31, | ||||||||||||||||||||||||
| 2009 | 2008 | 2007 | ||||||||||||||||||||||
|
%
|
%
|
%
|
||||||||||||||||||||||
| $ Value | Contribution | $ Value | Contribution | $ Value | Contribution | |||||||||||||||||||
| (In millions) | (In millions) | (In millions) | ||||||||||||||||||||||
|
Total Oil and Gas Revenues:
|
||||||||||||||||||||||||
|
United States
|
$ | 3,050 | 36 | % | $ | 5,083 | 41 | % | $ | 4,306 | 43 | % | ||||||||||||
|
Canada
|
877 | 10 | % | 1,651 | 14 | % | 1,393 | 14 | % | |||||||||||||||
|
North America
|
3,927 | 46 | % | 6,734 | 55 | % | 5,699 | 57 | % | |||||||||||||||
|
Egypt
|
2,553 | 30 | % | 2,739 | 22 | % | 2,012 | 20 | % | |||||||||||||||
|
Australia
|
363 | 4 | % | 372 | 3 | % | 536 | 6 | % | |||||||||||||||
|
North Sea
|
1,369 | 16 | % | 2,103 | 17 | % | 1,399 | 14 | % | |||||||||||||||
|
Argentina
|
362 | 4 | % | 380 | 3 | % | 316 | 3 | % | |||||||||||||||
|
International
|
4,647 | 54 | % | 5,594 | 45 | % | 4,263 | 43 | % | |||||||||||||||
|
Total(1)
|
$ | 8,574 | 100 | % | $ | 12,328 | 100 | % | $ | 9,962 | 100 | % | ||||||||||||
|
Oil Revenues:
|
||||||||||||||||||||||||
|
United States
|
$ | 1,922 | 32 | % | $ | 2,751 | 34 | % | $ | 2,202 | 35 | % | ||||||||||||
|
Canada
|
311 | 5 | % | 587 | 7 | % | 468 | 8 | % | |||||||||||||||
|
North America
|
2,233 | 37 | % | 3,338 | 41 | % | 2,670 | 43 | % | |||||||||||||||
|
Egypt
|
2,063 | 34 | % | 2,232 | 27 | % | 1,607 | 26 | % | |||||||||||||||
|
Australia
|
230 | 4 | % | 277 | 3 | % | 401 | 6 | % | |||||||||||||||
|
North Sea
|
1,356 | 22 | % | 2,085 | 26 | % | 1,389 | 22 | % | |||||||||||||||
|
Argentina
|
207 | 3 | % | 225 | 3 | % | 192 | 3 | % | |||||||||||||||
|
International
|
3,856 | 63 | % | 4,819 | 59 | % | 3,589 | 57 | % | |||||||||||||||
|
Total(2)
|
$ | 6,089 | 100 | % | $ | 8,157 | 100 | % | $ | 6,259 | 100 | % | ||||||||||||
40
Table of Contents
| Revenues for the Year Ended December 31, | ||||||||||||||||||||||||
| 2009 | 2008 | 2007 | ||||||||||||||||||||||
|
%
|
%
|
%
|
||||||||||||||||||||||
| $ Value | Contribution | $ Value | Contribution | $ Value | Contribution | |||||||||||||||||||
| (In millions) | (In millions) | (In millions) | ||||||||||||||||||||||
|
Natural Gas Revenues:
|
||||||||||||||||||||||||
|
United States
|
$ | 1,054 | 44 | % | $ | 2,204 | 56 | % | $ | 1,977 | 56 | % | ||||||||||||
|
Canada
|
547 | 23 | % | 1,026 | 26 | % | 892 | 26 | % | |||||||||||||||
|
North America
|
1,601 | 67 | % | 3,230 | 82 | % | 2,869 | 82 | % | |||||||||||||||
|
Egypt
|
490 | 21 | % | 507 | 13 | % | 404 | 12 | % | |||||||||||||||
|
Australia
|
133 | 6 | % | 95 | 2 | % | 134 | 4 | % | |||||||||||||||
|
North Sea
|
13 | 0 | % | 18 | 0 | % | 11 | 0 | % | |||||||||||||||
|
Argentina
|
132 | 6 | % | 115 | 3 | % | 86 | 2 | % | |||||||||||||||
|
International
|
768 | 33 | % | 735 | 18 | % | 635 | 18 | % | |||||||||||||||
|
Total(3)
|
$ | 2,369 | 100 | % | $ | 3,965 | 100 | % | $ | 3,504 | 100 | % | ||||||||||||
|
Natural Gas Liquids (NGL) Revenues:
|
||||||||||||||||||||||||
|
United States
|
$ | 74 | 64 | % | $ | 128 | 62 | % | $ | 127 | 64 | % | ||||||||||||
|
Canada
|
20 | 17 | % | 38 | 19 | % | 33 | 17 | % | |||||||||||||||
|
North America
|
94 | 81 | % | 166 | 81 | % | 160 | 81 | % | |||||||||||||||
|
Argentina
|
22 | 19 | % | 40 | 19 | % | 39 | 19 | % | |||||||||||||||
|
Total
|
$ | 116 | 100 | % | $ | 206 | 100 | % | $ | 199 | 100 | % | ||||||||||||
| (1) | Included in oil and gas production revenues for 2009, 2008 and 2007 were a gain of $180.8 million, a loss of $458.7 million and a loss of $32.5 million, respectively, from financial derivative hedging activities. | |
| (2) | Included in oil revenues for 2009, 2008 and 2007 were a gain of $45.2 million, a loss of $450.8 million and a loss of $96.6 million, respectively, from financial derivative hedging activities. | |
| (3) | Included in natural gas revenues for 2009, 2008 and 2007 were a gain of $135.6 million, a loss of $7.9 million and a gain of $64.1 million, respectively, from financial derivative hedging activities. |
| Production and Prices for the Year Ended December 31, | ||||||||||||||||||||
|
Increase
|
Increase
|
|||||||||||||||||||
| 2009 | (Decrease) | 2008 | (Decrease) | 2007 | ||||||||||||||||
|
Oil Volume — b/d:
|
||||||||||||||||||||
|
United States
|
89,133 | −1 | % | 89,797 | −1 | % | 90,759 | |||||||||||||
|
Canada
|
15,186 | −11 | % | 17,154 | −9 | % | 18,756 | |||||||||||||
|
North America
|
104,319 | −2 | % | 106,951 | −2 | % | 109,515 | |||||||||||||
|
Egypt
|
92,139 | +38 | % | 66,753 | +10 | % | 60,735 | |||||||||||||
|
Australia
|
9,779 | +19 | % | 8,249 | −40 | % | 13,778 | |||||||||||||
|
North Sea
|
60,984 | +3 | % | 59,494 | +11 | % | 53,632 | |||||||||||||
|
Argentina
|
11,505 | −7 | % | 12,409 | +8 | % | 11,440 | |||||||||||||
|
International
|
174,407 | +19 | % | 146,905 | +5 | % | 139,585 | |||||||||||||
|
Total(1)
|
278,726 | +10 | % | 253,856 | +2 | % | 249,100 | |||||||||||||
41
Table of Contents
| Production and Prices for the Year Ended December 31, | ||||||||||||||||||||
|
Increase
|
Increase
|
|||||||||||||||||||
| 2009 | (Decrease) | 2008 | (Decrease) | 2007 | ||||||||||||||||
|
Natural Gas Volume — Mcf/d:
|
||||||||||||||||||||
|
United States
|
666,084 | −2 | % | 679,876 | −12 | % | 769,596 | |||||||||||||
|
Canada
|
359,235 | +2 | % | 352,731 | −9 | % | 388,211 | |||||||||||||
|
North America
|
1,025,319 | −1 | % | 1,032,607 | −11 | % | 1,157,807 | |||||||||||||
|
Egypt
|
362,618 | +38 | % | 263,711 | +10 | % | 240,777 | |||||||||||||
|
Australia
|
183,617 | +49 | % | 123,003 | −37 | % | 194,928 | |||||||||||||
|
North Sea
|
2,703 | +3 | % | 2,637 | +36 | % | 1,933 | |||||||||||||
|
Argentina
|
184,557 | −6 | % | 195,651 | −3 | % | 200,903 | |||||||||||||
|
International
|
733,495 | +25 | % | 585,002 | −8 | % | 638,541 | |||||||||||||
|
Total(3)
|
1,758,814 | +9 | % | 1,617,609 | −10 | % | 1,796,348 | |||||||||||||
|
NGL Volume — b/d:
|
||||||||||||||||||||
|
United States
|
6,136 | +3 | % | 5,986 | −22 | % | 7,702 | |||||||||||||
|
Canada
|
2,089 | +1 | % | 2,076 | −8 | % | 2,246 | |||||||||||||
|
North America
|
8,225 | +2 | % | 8,062 | −19 | % | 9,948 | |||||||||||||
|
Argentina
|
3,241 | +12 | % | 2,887 | +3 | % | 2,800 | |||||||||||||
|
Total
|
11,466 | +5 | % | 10,949 | −14 | % | 12,748 | |||||||||||||
|
Average Oil price — Per barrel:
|
||||||||||||||||||||
|
United States
|
$ | 59.06 | −29 | % | $ | 83.70 | +26 | % | $ | 66.48 | ||||||||||
|
Canada
|
56.16 | −40 | % | 93.53 | +37 | % | 68.29 | |||||||||||||
|
North America
|
58.64 | −31 | % | 85.28 | +28 | % | 66.79 | |||||||||||||
|
Egypt
|
61.34 | −33 | % | 91.37 | +26 | % | 72.51 | |||||||||||||
|
Australia
|
64.42 | −30 | % | 91.78 | +15 | % | 79.79 | |||||||||||||
|
North Sea
|
60.91 | −36 | % | 95.76 | +35 | % | 70.93 | |||||||||||||
|
Argentina
|
49.42 | 0 | % | 49.46 | +8 | % | 45.99 | |||||||||||||
|
International
|
60.58 | −32 | % | 89.63 | +27 | % | 70.45 | |||||||||||||
|
Total(2)
|
59.85 | −32 | % | 87.80 | +28 | % | 68.84 | |||||||||||||
|
Average Natural Gas price — Per Mcf:
|
||||||||||||||||||||
|
United States
|
$ | 4.34 | −51 | % | $ | 8.86 | +26 | % | $ | 7.04 | ||||||||||
|
Canada
|
4.17 | −47 | % | 7.94 | +26 | % | 6.30 | |||||||||||||
|
North America
|
4.28 | −50 | % | 8.55 | +26 | % | 6.79 | |||||||||||||
|
Egypt
|
3.70 | −30 | % | 5.25 | +14 | % | 4.60 | |||||||||||||
|
Australia
|
1.99 | −5 | % | 2.10 | +11 | % | 1.89 | |||||||||||||
|
North Sea
|
13.15 | −30 | % | 18.78 | +25 | % | 15.03 | |||||||||||||
|
Argentina
|
1.96 | +22 | % | 1.61 | +38 | % | 1.17 | |||||||||||||
|
International
|
2.87 | −16 | % | 3.43 | +26 | % | 2.72 | |||||||||||||
|
Total(4)
|
3.69 | −45 | % | 6.70 | +25 | % | 5.34 | |||||||||||||
42
Table of Contents
| Production and Prices for the Year Ended December 31, | ||||||||||||||||||||
|
Increase
|
Increase
|
|||||||||||||||||||
| 2009 | (Decrease) | 2008 | (Decrease) | 2007 | ||||||||||||||||
|
Average NGL Price — Per barrel:
|
||||||||||||||||||||
|
United States
|
$ | 33.02 | −44 | % | $ | 58.62 | +30 | % | $ | 45.24 | ||||||||||
|
Canada
|
25.54 | −48 | % | 49.33 | +22 | % | 40.55 | |||||||||||||
|
North America
|
31.12 | −45 | % | 56.23 | +27 | % | 44.18 | |||||||||||||
|
Argentina
|
18.76 | −50 | % | 37.83 | 0 | % | 37.78 | |||||||||||||
|
Total
|
27.63 | −46 | % | 51.38 | +20 | % | 42.78 | |||||||||||||
| (1) | Approximately 10 percent of 2009 oil production was subject to financial derivative hedges, compared to 19 percent in 2008 and 17 percent in 2007. | |
| (2) | Reflects per-barrel increase of $.44 in 2009 and reductions of $4.85 in 2008 and $1.06 in 2007 from financial derivative hedging activities. | |
| (3) | Approximately nine percent of 2009 gas production was subject to financial derivative hedges, compared to 20 percent in 2008 and 17 percent in 2007. | |
| (4) | Reflects per-Mcf increase of $.21 in 2009, reduction of $.01 in 2008 and increase of $.10 in 2007 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 our control. Prices we received for
our crude oil in 2009 were 32 percent below 2008 with the
worldwide economic downturn. Apache uses financial instruments
to manage a portion of its exposure to fluctuations in crude oil
prices, particularly in North America. In 2009, 10 percent
of our oil production was subject to financial derivative
hedges, increasing revenues by $45 million. In 2008,
19 percent of our oil production was hedged, reducing oil
revenue by $451 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 Asian or Dated Brent benchmark
crude oil prices, which typically track at or above NYMEX oil
prices. In Argentina, we currently sell our oil in the domestic
market. The Argentine government previously imposed 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 its exposure
to fluctuations in natural gas prices, primarily in North
America. In 2009 nine percent of our gas production was subject
to financial derivative hedges, increasing revenues by
$136 million. In 2008 20 percent of our gas production
was hedged, reducing gas revenue by $8 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.
43
Table of Contents
Apache primarily sells natural gas into the North American
market, where spot prices were cut in half compared to 2008, and
various international markets, where our average contracted
prices declined just 16 percent from 2008. Our primary
markets include:
1) North America, which has a common market and where most
of our gas is sold on a monthly or daily basis at either monthly
or daily market prices.
2) Egypt, where the majority of our gas is sold to EGPC
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 beginning of 2013. The
region averaged $3.70 per Mcf in 2009.
3) Australia, which has a local market with mostly
long-term, fixed-price contracts that are periodically adjusted
for changes in the local consumer price index. Natural gas
discoveries are increasingly dedicated to the LNG market, and
supply is tightening for delivery to the domestic market. As a
result, recent contracts, including for our Reindeer field, are
substantially higher than historical levels.
4) Argentina, where 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
2009 we realized an average price of $1.07 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 2009. Our overall average realized price for 2009 was
$1.96 per Mcf, 22 percent higher than 2008 average realized
prices and 68 percent higher than 2007 average realized
prices.
During 2009 Apache received technical and commercial approval
from the government of Argentina for four Gas Plus projects and
technical approval for two more Gas Plus projects designed to
encourage new supplies through development of tight sands and
unconventional gas reserves. Under the Gas Plus program, Apache
has the opportunity to supply
10 MMcf/d
from fields in the Neuquén Province at a price of $4.10 per
MMBtu beginning January 1, 2010 for an initial one-year
term. The Company also has a letter of intent for a contract to
supply up to
50 MMcf/d
from fields in the Neuquén and Rio Negro Provinces for
$5.00 per MMbtu beginning January 1, 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 this type of 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
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. Crude oil revenues
for 2009 totaled $6.1 billion, $2.1 billion lower than
2008. The decrease was driven by a 32 percent decline in
average realized prices (-$2.6 billion), mitigated by the
impact of 10 percent production growth (+$528 million).
Worldwide production increased 24.9 Mb/d despite curtailed
capital spending, which was 40 percent lower than 2008.
Egypt’s 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 (NEAG) Extension and Khalda, waterflood
projects and increased condensate from additional Qasr gas
flowing through the new processing trains at the Salam Gas
Plant. Australia’s 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.
2008 vs. 2007
Crude oil accounted for
48 percent of our equivalent production and 66 percent
of our oil and gas production revenues for 2008, compared to 44
and 63 percent, respectively, for 2007. Crude oil revenues
for
44
Table of Contents
2008 totaled $8.2 billion, increasing $1.9 billion on
a 28 percent increase in average realized prices
(+$1.7 billion) and a two percent production growth
(+$175 million).
Worldwide production was up 4.8 Mb/d, driven by increases in the
North Sea and Egypt, which more than offset lower production in
Australia, Canada and the U.S. Production in the North Sea
was up 5.9 Mb/d (11 percent) on successful drilling and
workover programs and a reduction in platform downtime.
Egypt’s production increased 6.0 Mb/d (10 percent) on
higher gross production from wells at El Diyur, Umbarka and East
Bahariya and higher cost recovery from accelerated capital
spending on a gas plant expansion. Argentine production was up
1.0 Mb/d on increased production from new wells in Tierra del
Fuego. Australia’s production was down 5.5 Mb/d
(40 percent), split between shut-ins following a June 2008
pipeline explosion at the Varanus Island gas processing and
transportation hub and natural decline. Canada’s daily
production was 1.6 Mb/d lower on natural decline and
property divestitures, which more than offset drilling and
recompletion activity. U.S. production declined 1.0 Mb/d.
Production in the Gulf Coast region decreased 2.7 Mb/d; shut-in
production related to hurricanes reduced annual production by
6.9 Mb/d, offsetting net production growth from the regions
drilling program. The Central region’s production increased
1.7 Mb/d, driven by property acquisitions and drilling and
recompletion activity.
Natural
Gas Revenues
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. Gas revenues for
2009 totaled $2.4 billion, down $1.6 billion from
2008. All of the natural gas revenue decline occurred in North
America, as a 25 percent increase in international
production more than offset a 16 percent decline in
international price realizations.
Worldwide production grew
141 MMcf/d,
driven by a
99 MMcf/d
increase in Egypt’s net production and a
61 MMcf/d
increase in Australia. Egypt’s 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. The increased compression in the
Northern Gas Pipeline also allowed increased throughput at the
nearby Tarek plant and enabled us to begin producing previous
discoveries at the Jade and Falcon fields in our Matruh
concession. Australia’s 49 percent production increase
was driven by production restorations following completion of
repairs to the Varanus Island facility. Canada’s 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 region’s production declined
6 MMcf/d
primarily a result of the region’s 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.
2008 vs. 2007
Gas accounted for
50 percent of our equivalent production and 32 percent
of our oil and gas production revenues for 2008, compared to 53
and 35 percent, respectively, for 2007. Natural gas
revenues in 2008 totaled $4.0 billion and were
$461 million higher than 2007, reflecting a 25 percent
increase in realized natural gas prices (+$887 million),
which more than offset 10 percent lower production
(-$426 million).
Worldwide production decreased
179 MMcf/d.
Australian production was down
72 MMcf/d.
Volumes were impacted by production shut-in after an explosion
on an export pipeline and resulting fire that damaged our
processing facilities. U.S. production was
90 MMcf/d
lower. Gulf Coast daily production drove the lower
U.S. production, with a decrease of
99 MMcf/d.
The region’s production was negatively impacted by
properties shut-in for hurricanes
(55 MMcf/d)
and facility, rig and third-party downtime
(27 MMcf/d),
as well as the impact of a delay in the region’s drilling
program caused by the hurricanes. Central region production
increased
10 MMcf/d
on drilling and recompletion activities and from incremental
volumes from Permian Basin properties acquired in March 2007.
Canada’s production decreased
35 MMcf/d
on natural decline and property divestitures. Egypt’s gas
production increased
23 MMcf/d
(10 percent) on successful recompletions at our Matruh
concession, new wells
45
Table of Contents
brought online at the NEAG concession and higher cost recovery
from accelerated capital spending on gas plant expansion.
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 either on a boe
basis, on an absolute dollar basis or both, depending on
relevance. Amounts included in this table and in the discussion
below are rounded to millions and may differ slightly from those
presented elsewhere in this document.
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||
| (In millions) | (Per boe) | |||||||||||||||||||||||
|
Depreciation, depletion and amortization:
|
||||||||||||||||||||||||
|
Oil and gas property and equipment
|
||||||||||||||||||||||||
|
Recurring
|
$ | 2,202 | $ | 2,358 | $ | 2,208 | $ | 10.34 | $ | 12.06 | $ | 10.78 | ||||||||||||
|
Additional
|
2,818 | 5,334 | — | 13.24 | 27.27 | — | ||||||||||||||||||
|
Other assets
|
193 | 158 | 140 | .91 | .81 | .68 | ||||||||||||||||||
|
Asset retirement obligation accretion
|
105 | 101 | 96 | .49 | .52 | .47 | ||||||||||||||||||
|
Lease operating expenses
|
1,662 | 1,909 | 1,653 | 7.81 | 9.76 | 8.07 | ||||||||||||||||||
|
Gathering and transportation
|
143 | 157 | 137 | .67 | .80 | .67 | ||||||||||||||||||
|
Taxes other than income
|
579 | 985 | 598 | 2.72 | 5.03 | 2.92 | ||||||||||||||||||
|
General and administrative expenses
|
344 | 289 | 275 | 1.62 | 1.48 | 1.34 | ||||||||||||||||||
|
Financing costs, net
|
242 | 166 | 220 | 1.13 | .85 | 1.07 | ||||||||||||||||||
|
Total
|
$ | 8,288 | $ | 11,457 | $ | 5,327 | $ | 38.93 | $ | 58.58 | $ | 26.00 | ||||||||||||
Depreciation,
Depletion and Amortization
The following table details the changes in recurring
depreciation, depletion and amortization (DD&A) of oil and
gas properties between 2009 and 2007:
| Recurring DD&A | ||||
| (In millions) | ||||
|
2007
|
$ | 2,208 | ||
|
Volume change
|
(127 | ) | ||
|
Rate change
|
277 | |||
|
2008
|
$ | 2,358 | ||
|
Volume change
|
150 | |||
|
Rate change
|
(306 | ) | ||
|
2009
|
$ | 2,202 | ||
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.
Under the full-cost method of accounting, the Company is
required to review the carrying value of its proved oil and gas
properties each quarter on a
country-by-country
basis. Under these rules, capitalized costs of oil and gas
properties, net of accumulated DD&A and deferred income
taxes, may not exceed the present value of estimated
46
Table of Contents
future net cash flows from proved oil and gas reserves,
discounted 10 percent, net of related tax effects. Until
December 31, 2009, the rules generally required pricing
future net cash flows at the unescalated oil and gas prices in
effect at the end of each fiscal quarter. Effective
December 31, 2009, estimated future net cash flows is
calculated using an unweighted arithmetic average of commodity
prices in effect on the first day of each month in 2009, held
flat for the life of the production, except where prices are
defined by contractual arrangements. The rules also generally
require the estimation of future costs using costs in effect at
the end of each fiscal quarter. Write-downs required by these
rules do not impact cash flow from operating activities.
2008 vs. 2007
During 2008, recurring full-cost
depletion expense increased $150 million, $277 million
on rate, partially offset by $127 million on lower volumes.
Our full-cost depletion rate increased $1.28 to $12.06 per boe
on drilling and finding costs that exceeded our historical cost
basis. Higher industry-wide costs, which also impacted estimates
of future development costs, were driven by increased demand for
drilling services, a consequence of higher oil and gas prices.
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 Company’s 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.
2009 vs. 2008
Our 2009 LOE decreased
$247 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 | ||
47
Table of Contents
2008 vs. 2007
Our 2008 LOE increased
$256 million from 2007. LOE per boe was up 21 percent:
15 percent on higher cost and six percent on lower
production. The rate was impacted by the items below:
| Per boe | ||||
|
2007 LOE
|
$ | 8.07 | ||
|
Lower production
|
.45 | |||
|
Higher operating costs, including power and labor
|
.33 | |||
|
Workover costs
|
.29 | |||
|
Non-recurring repairs and maintenance
|
.07 | |||
|
Hurricane repairs
|
.07 | |||
|
Varanus Island repair costs
|
.03 | |||
|
Other
|
.45 | |||
|
2008 LOE
|
$ | 9.76 | ||
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, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In millions) | ||||||||||||
|
U.S.
|
$ | 35 | $ | 39 | $ | 38 | ||||||
|
Canada
|
53 | 64 | 54 | |||||||||
|
North Sea
|
26 | 28 | 27 | |||||||||
|
Egypt
|
24 | 21 | 15 | |||||||||
|
Argentina
|
5 | 5 | 3 | |||||||||
|
Total Gathering and Transportation
|
$ | 143 | $ | 157 | $ | 137 | ||||||
|
Total Gathering and Transportation per boe
|
$ | .67 | $ | .80 | $ | .67 | ||||||
2009 vs. 2008
Gathering and transportation
costs decreased $14 million from 2008. On a per unit basis,
gathering and transportation costs were down 16 percent:
nine percent on lower costs and seven percent on higher
production.
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.
2008 vs. 2007
Gathering and transportation
costs for 2008 increased $20 million from 2007. On a per
unit basis, gathering and transportation costs were up
19 percent: 15 percent on higher costs and four
percent on lower
48
Table of Contents
production. The increase was driven primarily by higher
transportation tariffs in Canada and an increase in Egyptian
export volumes.
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 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, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In millions) | ||||||||||||
|
U.K. PRT
|
$ | 383 | $ | 695 | $ | 346 | ||||||
|
Severance taxes
|
88 | 168 | 142 | |||||||||
|
Ad valorem taxes
|
55 | 71 | 56 | |||||||||
|
Other taxes
|
53 | 51 | 54 | |||||||||
|
Total Taxes other than income
|
$ | 579 | $ | 985 | $ | 598 | ||||||
|
Total Taxes other than income per boe
|
$ | 2.72 | $ | 5.03 | $ | 2.92 | ||||||
2009 vs. 2008
Taxes other than income were
$406 million lower than 2008. On a per unit basis, they
decreased 46 percent: 41 percent on lower costs and
five percent on higher production.
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.
2008 vs. 2007
Taxes other than income for 2008
were $387 million higher than 2007. On a per unit basis,
they increased 72 percent: 65 percent on higher costs
and seven percent on lower production.
U.K. PRT was $349 million more than 2007 on a
98 percent increase in net profits, driven by higher oil
revenues. The increase in severance taxes resulted from higher
taxable revenues in the U.S., consistent with the higher
realized oil and natural gas prices in the first nine months of
the year. The $15 million increase in ad valorem taxes
resulted from higher taxable valuations associated with
increases in oil and natural gas prices at the time the taxes
were assessed and a full year of taxes on the Permian Basin
properties acquired in the first quarter of 2007.
General
and Administrative Expenses
2009 vs. 2008
General and administrative
(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. The increase was
driven by $39 million of nonrecurring charges related to
the retirement of our founder and former chairman and employee
separation costs related to a 2009 workforce reduction.
Stock-based compensation expense increased $34 million on
the impact of higher stock appreciation relative to 2008 and new
awards issued in 2009. Insurance premiums were up
$9 million. These increases were partially offset by net
reductions in other corporate expenses of $27 million.
2008 vs. 2007
G&A expenses were
$14 million higher in 2008 compared to 2007. On a per boe
basis, G&A expenses increased 10 percent: five percent
on higher costs and five percent on lower volumes. The cost
increase was driven by higher legal fees, especially in our
international operations, increased incentive compensation
49
Table of Contents
expenses and miscellaneous higher costs in several departments,
partially offset by a decrease in stock-based compensation
expenses related to cash-settled stock appreciation rights.
Financing
Costs,
Net
Financing costs incurred during the periods noted are composed
of the following:
| For the Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In millions) | ||||||||||||
|
Interest expense
|
$ | 309 | $ | 280 | $ | 308 | ||||||
|
Amortization of deferred loan costs
|
6 | 4 | 3 | |||||||||
|
Capitalized interest
|
(61 | ) | (94 | ) | (75 | ) | ||||||
|
Interest Income
|
(12 | ) | (24 | ) | (16 | ) | ||||||
|
Total Financing costs
|
$ | 242 | $ | 166 | $ | 220 | ||||||
|
Financing costs per boe
|
$ | 1.13 | $ | .85 | $ | 1.07 | ||||||
2009 vs. 2008
Financing costs, net increased
$76 million from 2008. On a per unit basis, they increased
33 percent: 46 percent on higher costs, offset by a
13 percent reduction related to production growth.
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.
2008 vs. 2007
Financing costs, net for 2008
decreased $54 million from 2007. On a per unit basis, they
decreased 21 percent: 25 percent on lower costs and
four percent on production growth.
Interest expense was down $28 million on lower average
outstanding debt balances. Capitalized interest was up primarily
because of expenditures associated with long-term construction
projects under development.
Provision
for Income Taxes
2009 vs. 2008
There were no significant
changes in statutory tax rates in the major jurisdictions in
which the Company operates during 2009.
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
39.83 percent and 39.58 percent, respectively.
2008 vs. 2007
There were no significant
changes in statutory tax rates in the major jurisdictions in
which the Company operates during 2008. In 2007 we saw a
significant reduction to deferred income taxes resulting from
Canadian tax rate reductions.
The provision for income taxes decreased $1.6 billion from
2007 to $220 million, as income before taxes decreased
80 percent as a result of the $5.3 billion in
additional DD&A recorded in conjunction with the ceiling
test write-down. The effective income tax rate for the year was
23.6 percent compared to 39.8 percent in 2007. The
2008 effective rate was impacted by the magnitude of the taxes
related to the write-down, non-cash benefits related to the
effect of the strengthening U.S. dollar on our foreign
deferred tax liabilities and other net tax settlements. The 2007
effective rate was impacted by a non-cash charge related to the
effect of the weakening U.S. dollar on our foreign deferred
tax liabilities. Partially offsetting this charge was an out of
period benefit from Canadian federal tax rate reductions enacted
in the second and fourth quarters of 2007. Excluding these
items, the 2008 effective rate would have been comparable to the
2007 effective rate.
50
Table of Contents
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 results and believes the
presentation of these measures provides information useful in
assessing the Company’s 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 Company’s 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 Company’s results.
|
For the Year
|
||||||||
| Ended December 31, | ||||||||
| 2009 | 2008 | |||||||
| (In thousands, except per share data) | ||||||||
|
Income (Loss) Attributable to Common Stock (GAAP)
|
$ | (291,692 | ) | $ | 706,274 | |||
|
Adjustments:
|
||||||||
|
Foreign currency fluctuation impact on deferred tax expense
|
197,724 | (397,454 | ) | |||||
|
Additional depletion, net of tax(1)
|
1,981,398 | 3,647,745 | ||||||
|
Out-of-period
tax adjustments
|
— | (173,795 | ) | |||||
|
Adjusted Earnings (Non-GAAP)
|
$ | 1,887,430 | $ | 3,782,770 | ||||
|
Adjusted Earnings Per Share (Non-GAAP)
|
||||||||
|
Basic
|
$ | 5.62 | $ | 11.31 | ||||
|
Diluted
|
$ | 5.59 | $ | 11.22 | ||||
|
Average Number of Common Shares
|
||||||||
|
Basic
|
335,852 | 334,351 | ||||||
|
Diluted
|
337,737 | 337,191 | ||||||
| (1) | Additional depletion (non-cash write-down of the carrying value of proved property) recorded in 2009 was $2,818,161 pre-tax, for which a deferred tax benefit of $836,763 was recognized. Also, additional depletion was recorded in 2008 totaling $5,333,821 pre-tax, for which a deferred tax benefit of $1,686,076 was recognized. The tax effect of write-down of the carrying value of proved property (additional depletion) in both 2009 and 2008 were calculated utilizing the statutory rates in effect in each country where a write-down occurred. |
51
Table of Contents
Significant
Acquisitions and Divestitures
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 barrels of oil equivalent
per day 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
Apache’s existing properties in the Permian Basin,
particularly in Lea County, N.M., 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. These
divestitures were subject to normal post-closing adjustments.
2007
Activity
U.S. Gulf Coast Farm-in
On
September 6, 2007, Apache entered into an Exploration
Agreement with various EnerVest Partnerships (“EVP”)
for an initial term of four years whereby Apache committed to
spend $30 million in qualified expenditures to explore,
drill, produce and market hydrocarbons from specified
undeveloped formations across 400,000 net acres in Central
and East Texas. As of December 31, 2008, Apache had
fulfilled the $30 million commitment.
U.S. Permian Basin
On March 29,
2007, the Company closed its acquisition of controlling interest
in 28 oil and gas fields in the Permian Basin of West Texas from
Anadarko for $1 billion. Apache estimates that these fields
had proved reserves of 57 million barrels (MMbbls) of
liquid hydrocarbons and 78 billion cubic feet (Bcf) of
natural gas as of year-end 2006. The Company funded the
acquisition with debt. Apache and Anadarko entered into a
joint-venture arrangement to effect the transaction. The Company
entered into cash flow hedges for a portion of the crude oil and
natural gas production.
Capital
Resources and Liquidity
Net cash provided by operating activities (cash flows) is our
primary source of liquidity. Our 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 our 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.
Our 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 our 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.
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. Apache’s
ability to access the debt and equity capital markets is
supported by its investment-grade credit ratings.
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Table of Contents
We believe the liquidity and capital resource alternatives
available to Apache, as discussed in the Liquidity section of
this Capital Resources and Liquidity discussion, combined with
internally-generated cash flows, will be adequate to fund our
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.
Our 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 net
cash flows and budget our 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.
53
Table of Contents
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, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In millions) | ||||||||||||
|
Sources of Cash and Cash Equivalents:
|
||||||||||||
|
Net cash provided by operating activities
|
$ | 4,224 | $ | 7,065 | $ | 5,677 | ||||||
|
Sales of short-term investments
|
792 | — | — | |||||||||
|
Sales of property and equipment
|
2 | 308 | 67 | |||||||||
|
Project financing draw-downs
|
250 | 100 | — | |||||||||
|
Fixed-rate debt borrowings
|
— | 796 | 1,992 | |||||||||
|
Common stock activity
|
29 | 32 | 30 | |||||||||
|
Treasury stock activity
|
6 | 4 | 14 | |||||||||
|
Other
|
29 | 40 | 26 | |||||||||
| 5,332 | 8,345 | 7,806 | ||||||||||
|
Uses of Cash and Cash Equivalents:
|
||||||||||||
|
Capital expenditures(1)
|
3,631 | 5,823 | 4,782 | |||||||||
|
Purchase of short-term investments
|
— | 792 | — | |||||||||
|
Acquisitions
|
310 | 150 | 1,025 | |||||||||
|
Net commercial paper and bank loan repayments
|
2 | 200 | 1,412 | |||||||||
|
Payments on fixed-rate notes
|
100 | — | 173 | |||||||||
|
Redemption of preferred stock
|
98 | — | — | |||||||||
|
Dividends
|
209 | 239 | 205 | |||||||||
|
Other
|
115 | 85 | 224 | |||||||||
| 4,465 | 7,289 | 7,821 | ||||||||||
|
Increase (decrease) in cash and cash equivalents
|
$ | 867 | $ | 1,056 | $ | (15 | ) | |||||
| (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
Net
cash provided by operating activities (operating cash flows or
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.
Our average natural gas price realizations fluctuated throughout
2009, dipping from a high of $4.31 per Mcf in January to a low
of $3.29 in September before increasing to $4.16 in December.
Average realized prices in 2009 for natural gas fell
45 percent to $3.69 per Mcf. Our average crude oil
realizations saw a gradual increase from a low of $40.24 per
barrel in January 2009, peaking in November at $75.09, before
falling back to $71.13 in December. Crude oil prices averaged
$59.85 per barrel, down 32 percent from 2008.
In order to manage the variability in cash flows, we increased
our commodity hedge positions during the third and fourth
quarters of 2009. At the end of 2009, we had hedged an average
of just over 450,000 MMBtu per day of our projected 2010
North American natural gas production. The volumes were
primarily hedged using fixed-price swaps at an average price of
approximately $5.65 per MMBtu. For perspective, the natural gas
hedges represent 41 percent of fourth-quarter 2009 North
America daily gas production; 24 percent worldwide. We also
had an average of just over 35,000 b/d of oil production hedged
for 2010. Crude oil production was primarily hedged using
collars that had average floor and ceiling prices of
approximately $65.00 and $80.80 per barrel, respectively. For
perspective, the oil hedges represent 13 percent of
fourth-quarter 2009 worldwide daily oil production. For
additional information regarding our derivative contracts,
please see Note 3 — Derivative Instruments and
Hedging
54
Table of Contents
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.
For 2009 operating cash flows totaled $4.2 billion, down
$2.8 billion from 2008. The primary driver of the reduction
was a $3.8 billion decrease in oil and gas revenues, with
the impact of lower commodity prices more than offsetting a nine
percent increase in equivalent daily production. Also negatively
impacting operating cash flows was the change in working capital
from year-end 2008 to year-end 2009. These items were partially
offset by the impact of a decline in cash-based expenses and
lower current taxes.
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.
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, 2009.
Project Financing Draw-downs
One of the
Company’s Australian subsidiaries has a secured revolving
syndicated credit facility for its Van Gogh and Pyrenees oil
developments offshore Western Australia. The outstanding balance
under the facility increased $250 million during the year
to $350 million at December 31, 2009. For a more
detailed discussion of this facility and information regarding
our available committed borrowing capacity, please see
“Liquidity” in this Item 7.
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,
management primarily relies on annual operating cash flow
forecasts. Annual 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 our operating cash
flows, borrowings under the our lines of credit and commercial
paper program and, from time to time, issues of public debt or
common stock to fund significant acquisitions.
55
Table of Contents
The following table details capital expenditures for each
country in which we do business.
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In millions) | ||||||||||||
|
Exploration and Development:
|
||||||||||||
|
United States
|
$ | 929 | $ | 2,183 | $ | 1,631 | ||||||
|
Canada
|
412 | 705 | 651 | |||||||||
|
North America
|
1,341 | 2,888 | 2,282 | |||||||||
|
Egypt
|
676 | 853 | 605 | |||||||||
|
Australia
|
602 | 880 | 516 | |||||||||
|
North Sea
|
375 | 459 | 538 | |||||||||
|
Argentina
|
140 | 318 | 287 | |||||||||
|
Chile
|
11 | 27 | — | |||||||||
|
International
|
1,804 | 2,537 | 1,946 | |||||||||
|
Worldwide Exploration and Development Costs
|
3,145 | 5,425 | 4,228 | |||||||||
|
Gathering, Transmission and Processing Facilities:
|
||||||||||||
|
Canada
|
83 | 29 | 24 | |||||||||
|
Egypt
|
151 | 571 | 422 | |||||||||
|
Australia
|
69 | 54 | 14 | |||||||||
|
Argentina
|
2 | 5 | 13 | |||||||||
|
Total Gathering, Transmission and Processing Facility Cost
|
305 | 659 | 473 | |||||||||
|
Asset Retirement Costs
|
293 | 514 | 439 | |||||||||
|
Capitalized Interest
|
61 | 94 | 76 | |||||||||
|
Capital Expenditures, excluding Acquisitions
|
3,804 | 6,692 | 5,216 | |||||||||
|
Acquisitions
|
310 | 150 | 1,025 | |||||||||
|
Total Capital Expenditures
|
$ | 4,114 | $ | 6,842 | $ | 6,241 | ||||||
Exploration and Development (E&D)
As
planned, our 2009 worldwide exploration and development
(E&D) expenditures were 42 percent lower than 2008. We
reduced 2009 expenditures in response to the precipitous decline
in commodity prices and the uncertainties surrounding the
financial crisis in late 2008 and early in 2009, seeking to keep
capital spending in line with 2009 operating cash flows.
Consequently, our E&D investments in all countries were
down. E&D spending in North America was 54 percent
less than the prior year as we lowered activity and concentrated
on identifying drilling opportunities and building inventory.
Investments in Egypt were $177 million lower than the prior
year as we scaled back drilling activity in the Western Desert.
However, Egypt’s percentage of worldwide E&D spending
rose to 21 percent, up from 16 percent.
Australia’s E&D expenditures were 32 percent
below 2008 on lower drilling activity and lower investments in
platforms and production facilities. North Sea E&D
expenditures were $84 million lower as their investment
requirements dropped following completion of several platform
upgrades in 2008.
Acquisitions
We completed $310 million of
acquisitions in 2009 compared to $150 million in 2008.
Acquisition capital expenditures occur as attractive
opportunities arise and, therefore, vary from year to year.
Asset Retirement Costs
In 2009 we recorded
$293 million of additional future asset retirement costs
associated with continued worldwide drilling programs,
acquisition activity and further assessment of Hurricane Ike
damages.
Gathering, Transmission and Processing Facilities
(GTP)
We invested $305 million in GTP
facilities in 2009 compared to $659 million in 2008. In
Egypt we invested $151 million in gas processing facilities
to alleviate
56
Table of Contents
capacity constraints, which were restricting production. We also
invested $69 million in Australia on GTP projects currently
in process. In Canada, we invested $83 million in
processing plants.
2010 Outlook
In order to preserve our strong
balance sheet and financial flexibility, we plan to keep
E&D capital spending generally in line with 2010 operating
cash flows. While funds have been committed for certain 2010
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 will closely monitor
commodity prices, service cost levels and predicted operating
cash and will adjust our exploration and development budgets
accordingly. However, with $2.0 billion of cash on our
balance sheet, we have the flexibility to utilize this surplus
for acquisitions or drilling and development projects that might
otherwise not progress. Because we typically revise our
exploration and development capital budgets throughout the year
depending on prices, projecting future expenditures is somewhat
difficult. Our current 2010 capital budget includes exploration
and development capital of approximately $6.0 to
$6.5 billion, including GTP. We generally do not project
capital estimates for acquisitions because they are specific
discrete events whose occurrence and timing is unpredictable.
Any acquisitions could be funded from operating cash flow,
credit facilities, new equity, or a combination thereof.
Payments on Fixed-rate Notes
The
$100 million Apache Finance Pty Ltd (Apache Finance
Australia) 7.0-percent notes matured on March 15, 2009. The
notes were repaid using existing cash balances.
Redemption of Preferred Stock
The Company
redeemed with cash all of its 5.68-percent Cumulative
Series B Preferred Stock on December 30, 2009. The
100,000 outstanding shares of Series B Preferred Stock were
redeemed at a redemption price of $1,000 per share, plus $9.47
in accrued and unpaid dividends.
Dividends
The Company has paid cash dividends
on its common stock for 45 consecutive years through 2009.
Future dividend payments will depend on the Company’s level
of earnings, financial requirements and other relevant factors.
Common stock dividends paid during 2009 totaled
$201 million, compared with $234 million in 2008 and
$199 million in 2007. The 2008 period included a special
non-recurring cash dividend of 10 cents per common share paid on
March 18, 2008.
As discussed above, on December 30, 2009, the Company
redeemed with cash all of its 5.68-percent Cumulative
Series B Preferred Stock. As a result, the Company paid a
total of $6.6 million of dividends, which includes two
months of dividends accelerated because of the redemption. Also,
in conjunction with the redemption of these shares, the Company
was required to classify $1.6 million of the redemption
amount ($100 million face value less $98.4 million
carrying value) as preferred stock dividends. During 2008 and
2007 the Company paid $5.7 million of dividends each year.
For additional information, please see Note 7 —
Capital Stock in the Notes to Consolidated Financial Statements
set forth in Part IV, Item 15 of this
Form 10-K.
Liquidity
| At December 31, | ||||||||
|
(Millions of Dollars Except as Indicated)
|
2009 | 2008 | ||||||
|
Cash and cash equivalents
|
$ | 2,048 | $ | 1,181 | ||||
|
Short-term investments
|
— | 792 | ||||||
|
Restricted cash
|
— | 14 | ||||||
|
Total debt
|
5,067 | 4,922 | ||||||
|
Shareholders’ equity
|
15,779 | 16,509 | ||||||
|
Available committed borrowing capacity
|
2,300 | 2,550 | ||||||
|
Floating-rate debt/total debt
|
7 | % | 2 | % | ||||
|
Percent of total debt to capitalization
|
24 | % | 23 | % | ||||
Our liquidity and financial position have not been materially
affected by the ongoing turmoil 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-six of 27 banks with lending commitments to the
Company have credit ratings of at least single-A, which in some
cases is
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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 27 banks in our bank group. Having a large
bank group allows the Company to mitigate the impact of any
bank’s failure to honor its lending commitment.
Cash and Cash Equivalents
We had
$2.05 billion in cash and cash equivalents at
December 31, 2009. At December 31, 2009,
$1.4 billion of cash was held by foreign subsidiaries and
approximately $650 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. We
held $1.2 billion in cash and cash equivalents at
December 31, 2008.
Short-term Investments
We occasionally invest
in highly-liquid, short-term investments. As needed, we may
reduce such short-term investment balances to further supplement
our operating cash flows. As of December 31, 2009, Apache
held no short-term investments. At December 31, 2008, the
Company had $792 million invested in obligations of the
U.S. government with original maturities greater than three
months but less than a year.
Restricted Cash
The Company classifies cash
balances as restricted cash when it is restricted as to
withdrawal or usage. As of December 31, 2008, we had
approximately $14 million of property divestiture proceeds
classified as restricted cash and held in escrow available for
use in a like-kind exchange under Section 1031 of the
U.S. federal income tax code. The Company expected to use
these funds to purchase noncurrent assets. Accordingly, the
restricted cash was classified as long-term at year-end.
Subsequent to year-end 2008 the time limits pursuant to
Section 1031 expired and the funds were transferred to
cash. As of December 31, 2009, no cash balances were
classified as restricted cash.
Debt
At December 31, 2009, outstanding
debt, which consisted of notes, debentures, uncommitted bank
lines and project financing, totaled $5.1 billion. Current
debt includes $110 million of loans under the Apache PVG
Pty Ltd credit facility due in 2010 and $7 million borrowed
under uncommitted overdraft lines in Argentina. We have
$100 million of debt maturing in 2011, $480 million
maturing in 2012, $945 million maturing in 2013,
$15 million maturing in 2014, and the remaining
$3.4 billion maturing intermittently in years 2015 through
2096.
Debt-to-Capitalization
Ratio
The Company’s
debt-to-capitalization
ratio as of December 31, 2009 was 24 percent.
Available Credit Facilities
As of
December 31, 2009, the Company had unsecured committed
revolving syndicated bank credit facilities totaling
$2.3 billion, which mature in May 2013. The facilities
consist of 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
(U.S. credit facilities) also allow the company to borrow
under competitive auctions. The U.S. credit facilities are
used to support Apache’s 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 Company’s 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
Company’s consolidated assets, or approximately
$1.4 billion as of December 31, 2009. There are no
restrictions on incurring liens in countries other than
U.S. and Canada. There are also restrictions on
Apache’s 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 (MAC clauses). 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-
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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, 2009.
At the Company’s option, the interest rate for the
facilities is based on (i) the greater of (a) the JP
Morgan Chase Bank prime rate or (b) the federal funds rate
plus one-half of one percent or (ii) the London Inter-bank
Offered Rate (LIBOR) plus a margin determined by the
Company’s senior long-term debt rating.
At December 31, 2009, the margin over LIBOR for committed
loans was .19 percent on the $1.5 billion facility and
.23 percent on the other three facilities. 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
Company’s senior long-term debt rating.
One of the Company’s Australian subsidiaries has a secured
revolving syndicated credit facility for its Van Gogh and
Pyrenees oil developments offshore Western Australia. The
facility provides for total commitments of up to
$350 million, with availability determined by a borrowing
base formula. The borrowing base was set at $350 million
and will be redetermined after the fields commence production in
the first half of 2010 and certain tests have been met, and
semi-annually thereafter. The facility is secured by certain
assets associated with the Van Gogh and Pyrenees oil
developments, including the shares of stock of the
Company’s subsidiary holding the assets. The Company agreed
to guarantee the credit facility until project completion occurs
pursuant to terms of the facility, which is expected in the
fourth quarter of 2010. In the event project completion does not
occur by December 31, 2010, pursuant to terms of the
facility the lenders may require repayment of outstanding
amounts in the first quarter of 2011. Interest is based on
LIBOR, which may be subject to change under certain market
disruption conditions, plus a margin of 1.00 percent
pre-completion and 1.75 percent post-completion. The
pre-completion margin increases to 1.125 percent in the
event the Company’s ratings are downgraded to BBB+ or below
by at least two major rating agencies. As of December 31,
2009 and 2008, there was $350 million and
$100 million, respectively, outstanding under the facility.
The commitments under the facility will be reduced by scheduled
increments every six months beginning June 30, 2010, with
final maturity on March 31, 2014. The outstanding amount
under this facility must not exceed $300 million on
June 30, 2010 and $240 million on December 31,
2010. Accordingly, $50 million and $60 million of the
current balance will be repaid by June 30, 2010 and
December 31, 2010, respectively and has been classified as
current debt at December 31, 2009.
Commercial Paper Program
The Company has
available a $1.95 billion commercial paper program, which
generally enables Apache to borrow funds for up to 270 days
at competitive interest rates. If the Company is unable to issue
commercial paper following a significant credit downgrade or
dislocation in the market, the Company’s 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 2013. As of December 31, 2009 and 2008, the
Company had no outstanding commercial paper.
Credit Ratings
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,
reserve mix and commodity pricing levels could also be
considered by the rating agencies. Apache’s senior
unsecured long-term debt is currently rated A3 by Moody’s,
A- by Standard & Poor’s and A- by Fitch. The
Company has received short-term debt ratings for its commercial
paper program of
P-2
from
Moody’s,
A-2
from
Standard & Poor’s and F2 from Fitch. In September
2009 Fitch downgraded Apache’s senior unsecured long-term
debt and short-term debt from A and F1 to A- and F2,
respectively. The current outlook at all three rating agencies
is stable. A further 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 in certain circumstances.
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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 Company’s contractual
obligations as of December 31, 2009. 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
|
2016 &
|
|||||||||||||||||||||
|
Contractual Obligations
|
Reference | Total | 2010 | 2011-2013 | 2014-2015 | Beyond | ||||||||||||||||
| (In millions) | ||||||||||||||||||||||
|
Debt
|
Note 5 | $ | 5,088 | $ | 117 | $ | 1,525 | $ | 365 | $ | 3,081 | |||||||||||
|
Interest payments
|
Note 5 | 4,812 | 296 | 830 | 433 | 3,253 | ||||||||||||||||
|
Drilling rig commitments
|
Note 8 | 481 | 419 | 62 | — | — | ||||||||||||||||
|
Purchase obligations
|
Note 8 | 611 | 382 | 229 | — | — | ||||||||||||||||
|
E&D commitments
|
Note 8 | 446 | 125 | 254 | 67 | — | ||||||||||||||||
|
Firm transportation agreements
|
Note 8 | 314 | 50 | 131 | 80 | 53 | ||||||||||||||||
|
Office and related equipment
|
Note 8 | 124 | 26 | 61 | 13 | 24 | ||||||||||||||||
|
Oil and gas operations equipment
|
Note 8 | 468 | 82 | 123 | 52 | 211 | ||||||||||||||||
|
Other
|
Note 8 | 5 | 5 | — | — | — | ||||||||||||||||
|
Total Contractual
Obligations(a)(b)(c)(d) |
$ | 12,349 | $ | 1,502 | $ | 3,215 | $ | 1,010 | $ | 6,622 | ||||||||||||
| (a) | This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1.8 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 Company’s $266 million net liability for outstanding derivative instruments valued as of December 31, 2009. 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 Company’s 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 Company’s 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. |
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. Apache’s management
feels that it has adequately reserved for its contingent
obligations, including approximately $27 million for
environmental remediation and approximately $20 million for
various contingent legal liabilities. For a detailed discussion
of the Company’s 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 accrued approximately $63 million as of
December 31, 2009, for an insurance contingency as a member
of Oil Insurance Limited (OIL). This insurance co-op insures
specific property, pollution liability and
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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.
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 Apache’s 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 Apache’s most
critical accounting policies:
Reserve
Estimates
In January 2009, the SEC issued Release
No. 33-8995,
“Modernization of Oil and Gas Reporting” (Release
33-8995),
amending oil and gas reporting requirements under
Rule 4-10
of
Regulation S-X
and Industry Guide 2 in
Regulation S-K
and bringing full-cost accounting rules into alignment with the
revised disclosure requirements. 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.
In January 2010, the Financial Accounting Standards Board (FASB)
issued Accounting Standards Update (ASU)
No. 2010-03,
“Oil and Gas Reserve Estimation and Disclosures” (ASU
2010-03),
which amends Accounting Standards Codification (ASC) Topic 932,
“Extractive Industries — Oil and Gas
”
to align the guidance with the changes made by the SEC. The
Company adopted Release
33-8995
and
the amendments to ASC Topic 932 resulting from ASU
2010-03
(collectively, the Modernization Rules) effective
December 31, 2009.
Proved oil and gas reserves are the estimated quantities of
natural gas, crude oil, condensate and NGL’s 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, 2009 were calculated using an
unweighted arithmetic average of commodity prices in effect on
the first day of each month in 2009, held flat for the life of
the production, except where prices are defined
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by contractual arrangements. Reserves as of December 31,
2008 and 2007 were estimated using prices in effect at the end
of those years, 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. Apache’s 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 because most of the removal obligations are many years
in the future, and contracts and regulation often have vague
descriptions of what constitutes removal. Asset removal
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 is recorded at fair value, and accretion expense is
recognized over time as the discounted liability is accreted to
its expected settlement value.
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.
Income
Taxes
Our oil and gas exploration and production operations are
currently located in six countries. As a result, we are subject
to taxation on our income in numerous jurisdictions. 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.
| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about
our 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 Company’s 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
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volatile due to unpredictable events such as economical growth
or retraction, weather and climate. Our average monthly crude
oil realizations saw a gradual increase from a low of $40.24 per
barrel in January 2009, peaking in November at $75.09, before
falling back to $71.13 in December. In 2009 crude oil prices
averaged $59.85 per barrel down 32 percent from 2008. Our
average monthly natural gas price realizations fluctuated
throughout 2009, dipping from a high of $4.31 per Mcf in January
to a low of $3.29 in September before increasing to $4.16 in
December. Average realized prices in 2009 for natural gas fell
45 percent to $3.69 per Mcf.
For 2009 approximately nine percent of our natural gas
production was subject to financial derivative hedges. In the
third and fourth quarters of 2009, we entered into additional
hedges on our 2010 projected North American gas production. For
perspective, these 2010 hedges represent approximately
24 percent of our fourth-quarter 2009 worldwide daily gas
volumes and approximately 41 percent of our fourth-quarter
2009 North American daily gas production.
For 2009 approximately 10 percent of our crude oil
production was subject to financial derivative hedges. In the
third and fourth quarters of 2009, we entered into additional
crude oil hedges on our 2010 projected production. For
perspective, these 2010 hedges represent approximately
13 percent of our fourth-quarter 2009 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 Company’s 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, 2009, the Company had open natural gas
derivative hedges in an asset position with a fair value of
$56 million. A 10 percent increase in natural gas
prices would reduce the fair value by approximately
$128 million, while a 10 percent decrease in prices
would increase the fair value by approximately
$127 million. The Company also had open oil derivatives in
a liability position with a fair value of $322 million. A
10 percent increase in oil prices would increase the
liability by approximately $202 million, while a
10 percent decrease in prices would decrease the liability
by approximately $190 million. These fair value changes
assume volatility based on prevailing market parameters at
December 31, 2009. For notional volumes and terms
associated with the Company’s 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, comprising the
President (principal financial officer), General Counsel,
Treasurer and other key members of Apache’s management,
approve and oversee 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, 2009, the Company’s debt with fixed
interest rates represented approximately 93 percent of
total debt. As a result, the interest expense on approximately
seven percent of Apache’s debt will fluctuate based on
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 $537,000.
Foreign
Currency Risk
The Company’s 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
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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 Company’s 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, 2009, would result in a foreign currency net
loss or gain, respectively, of approximately $95 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, 2009, 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:
| • | the market prices of oil, natural gas, NGLs and other products or services; | |
| • | our commodity hedging arrangements; | |
| • | the supply and demand for oil, natural gas, NGLs and other products or services; | |
| • | production and reserve levels; | |
| • | drilling risks; | |
| • | economic and competitive conditions; | |
| • | the availability of capital resources; | |
| • | capital expenditure and other contractual obligations; | |
| • | currency exchange rates; | |
| • | weather conditions; | |
| • | inflation rates; | |
| • | the availability of goods and services; | |
| • | legislative or regulatory changes; | |
| • | terrorism; | |
| • | occurrence of property acquisitions or divestitures; | |
| • | 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 — Management’s 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.
65
Table of Contents
| 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-64
in Part IV, Item 15 of this
Form 10-K
and are incorporated herein by reference.
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
The financial statements for the fiscal years ended
December 31, 2009, 2008 and 2007, included in this report,
have been audited by Ernst & Young LLP, registered
public accounting firm, as stated in their audit report
appearing herein.
| ITEM 9A. | CONTROLS AND PROCEDURES |
Disclosure
Controls and Procedures
G. Steven Farris, the Company’s Chairman and Chief
Executive Officer, in his capacity as principal executive
officer, and Roger B. Plank, the Company’s President, in
his capacity as principal financial officer, evaluated the
effectiveness of our disclosure controls and procedures as of
December 31, 2009, 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 Company’s
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 Commission’s 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, 2009, that have
materially affected, or are reasonably likely to materially
affect, the Company’s 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.
Management’s
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, 2009, that
has materially affected, or is reasonably likely to materially
affect, our internal controls over financial reporting.
| ITEM 9B. | OTHER INFORMATION |
None.
66
Table of Contents
PART III
| ITEM 10. | 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 Company’s 2010 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), which also meets the
requirements of a code of ethics under Item 406 of
Regulation S-K.
You can access the Company’s Code of Conduct on the
Management and Governance page of the Company’s 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 Company’s corporate secretary at the address on the
cover of this
Form 10-K.
Changes in and waivers to the Code of Conduct for the
Company’s directors, chief executive officer and certain
senior financial officers will be posted on the Company’s
website within five business days and maintained for at least
12 months.
| ITEM 11. | 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.
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT |
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.
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
The information set forth under the captions “Certain
Business Relationships and Transactions” and “Director
Independence” in the Proxy Statement is incorporated herein
by reference.
| ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The information set forth under the caption “Independent
Auditors” in the Proxy Statement is incorporated herein by
reference.
67
Table of Contents
PART IV
| ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K |
(a) Documents included in this report:
1.
Financial Statements
| F-1 | ||||
| F-2 | ||||
|
Report of independent registered public accounting firm
|
F-3 | |||
| F-4 | ||||
| F-5 | ||||
| F-6 | ||||
| F-7 | ||||
| F-8 |
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 Company’s financial
statements and related notes.
3.
Exhibits
|
Exhibit
|
||||||
|
No.
|
Description
|
|||||
| *3 | .1 | — | Restated Certificate of Incorporation of Registrant, dated February 23, 2010, as filed with the Secretary of State of Delaware on February 23, 2010. | |||
| 3 | .2 | — | Bylaws of Registrant, as amended August 6, 2009 (incorporated by reference to Exhibit 3.2 to Registrant’s Quarterly Report on Form 10-K for quarter ended June 30, 2009, SEC File No. 001-4300). | |||
| 4 | .1 | — | Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 001-4300). | |||
| 4 | .2 | — | 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 Registrant’s common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit(a) to Registrant’s Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 001-4300). | |||
| 4 | .3 | — | 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 Registrant’s Amendment No. 1 to Registration Statement on Form 8-A, dated January 31, 2006, SEC File No. 001-4300). | |||
| 4 | .4 | — | 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 Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536). | |||
68
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|
Exhibit
|
||||||
|
No.
|
Description
|
|||||
| 4 | .5 | — | 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 Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536). | |||
| 4 | .6 | — | 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 Registrant’s Registration Statement on Form S-3, dated November 12, 1997, Reg. No. 333-339973). | |||
| 4 | .7 | — | 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 Registrant’s Registration Statement on Form S-3, dated November 12, 1999, Reg. No. 333-90147). | |||
| 10 | .1 | — | 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Société Générale, as U.S. Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.01 to Registrant’s 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 10.02 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300). | |||
69
Table of Contents
|
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 10.03 to Registrant’s 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 Registrant’s 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 Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, SEC File No. 001-4300). | |||
| †10 | .9 | — | Apache Corporation Corporate Incentive Compensation Plan A (Senior Officers’ Plan), dated July 16, 1998 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300). Apache Corporation Corporate Incentive Compensation Plan A (Senior Officers’ Plan), dated July 16, 1998 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300). | |||
| †10 | .10 | — | 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 Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
| †10 | .11 | — | Apache Corporation Corporate Incentive Compensation Plan B (Strategic Objectives Format), dated July 16, 1998 (incorporated by reference to Exhibit 10.14 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300). | |||
| †10 | .12 | — | 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 Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
| †10 | .13 | — | Apache Corporation 401(k) Savings Plan, dated January 1, 2008 (incorporated by reference to Exhibit 10.20 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
| †10 | .14 | — | Amendment to Apache Corporation 401(k) Savings Plan, dated January 29, 2009, effective as of January 1, 2009, except as otherwise specified (incorporated by reference to Exhibit 10.21 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
| *†10 | .15 | — | Amendment to Apache Corporation 401(k) Savings Plan, dated December 22, 2009, effective as of January 1, 2009, except as otherwise specified. | |||
| *†10 | .16 | — | Non-Qualified Retirement/Savings Plan of Apache Corporation, amended and restated as of February 11, 2010. | |||
| *†10 | .17 | — | Apache Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated effective as of December 31, 2009. | |||
| †10 | .18 | — | Apache Corporation 1998 Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300). | |||
70
Table of Contents
|
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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.35 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
| †10 | .26 | — | Apache Corporation Deferred Delivery Plan, as amended and restated November 19, 2008, effective as of January 1, 2009, except as otherwise specified (incorporated by reference to Exhibit 10.36 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, 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 Registrant’s 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 November 20, 2008, effective as of January 1, 2009 (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
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|
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 Registrant’s 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 Registrant’s 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 Registrant’s 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. | |||
| *†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. | |||
| *†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. | |||
| *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 (incorporated by reference to Exhibit 14.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300). | |||
| *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 | |||
| *99 | .1 | — | Report of Ryder Scott Company L.P., Petroleum Consultants | |||
| **101 | — | The following materials from the Apache Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009, 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 Registrant’s
consolidated assets have been omitted and will be provided to
the Commission upon request.
72
Table of Contents
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
/s/
G.
STEVEN FARRIS
G. Steven Farris
Chairman of the Board and Chief Executive Officer
Dated: February 26, 2010
POWER OF
ATTORNEY
The officers and directors of Apache Corporation, whose
signatures appear below, hereby constitute and appoint G. Steven
Farris, Roger B. Plank, 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
|
Chairman of the Board and Chief Executive Officer
(principal executive officer) |
February 26, 2010 | ||||
|
/s/
ROGER
B. PLANK
|
President
(principal financial officer) |
February 26, 2010 | ||||
|
/s/
REBECCA
A. HOYT
|
Vice President and Controller
(principal accounting officer) |
February 26, 2010 | ||||
|
/s/
FREDERICK
M. BOHEN
|
Director | February 26, 2010 | ||||
|
/s/
RANDOLPH
M. FERLIC
|
Director | February 26, 2010 | ||||
|
/s/
EUGENE
C. FIEDOREK
|
Director | February 26, 2010 | ||||
|
/s/
A.
D. FRAZIER, JR.
|
Director | February 26, 2010 | ||||
|
/s/
PATRICIA
ALBJERG GRAHAM
|
Director | February 26, 2010 | ||||
73
Table of Contents
|
Name
|
Title
|
Date
|
||||
|
/s/
JOHN
A. KOCUR
|
Director | February 26, 2010 | ||||
|
/s/
GEORGE
D. LAWRENCE
|
Director | February 26, 2010 | ||||
|
/s/
F.
H. MERELLI
|
Director | February 26, 2010 | ||||
|
/s/
RODMAN
D. PATTON
|
Director | February 26, 2010 | ||||
|
/s/
CHARLES
J. PITMAN
|
Director | February 26, 2010 | ||||
74
Table of Contents
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 management’s 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 (Exchange Act). The
Company’s 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 on 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
Company’s 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 Company’s
internal control over financial reporting as of
December 31, 2009. In making this assessment, management
used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) 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, 2009.
The Company’s independent auditors, Ernst & Young
LLP, a registered public accounting firm, are appointed by the
Audit Committee of the Company’s 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 Company’s
internal control over financial reporting. The reports of the
independent auditors follow this report on pages F-2 and F-3.
G. Steven Farris
Chairman of the Board and Chief Executive Officer
(principal executive officer)
Chairman of the Board and Chief Executive Officer
(principal executive officer)
Roger B. Plank
President
(principal financial officer)
President
(principal financial officer)
Rebecca A. Hoyt
Vice President and Controller
(principal accounting officer)
Vice President and Controller
(principal accounting officer)
Houston, Texas
February 26, 2010
F-1
Table of Contents
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, 2009
and 2008, and the related consolidated statements of operations,
shareholders’ equity, and cash flows for each of the three
years in the period ended December 31, 2009. These
financial statements are the responsibility of the
Company’s 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, 2009 and 2008, and the consolidated results of
their operations and their cash flows for each of the three
years in the period ended December 31, 2009, 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 Corporation’s internal control over financial
reporting as of December 31, 2009, based on criteria
established in Internal Control-Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 26, 2010,
expressed an unqualified opinion thereon.
ERNST &
YOUNG LLP
Houston, Texas
February 26, 2010
F-2
Table of Contents
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, 2009, 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 Management’s Report on
Internal Control over Financial Reporting. Our responsibility is
to express an opinion on the company’s 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 company’s 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 company’s
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
company’s 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, 2009, 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, 2009 and 2008, and the
related consolidated statements of operations,
shareholders’ equity, and cash flows for each of the three
years in the period ended December 31, 2009 of Apache
Corporation and subsidiaries, and our report dated
February 26, 2010, expressed an unqualified opinion thereon.
ERNST &
YOUNG LLP
Houston, Texas
February 26, 2010
F-3
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
STATEMENT
OF CONSOLIDATED OPERATIONS
| For the Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands, except per common share data) | ||||||||||||
|
REVENUES AND OTHER:
|
||||||||||||
|
Oil and gas production revenues
|
$ | 8,573,927 | $ | 12,327,839 | $ | 9,961,982 | ||||||
|
Other
|
40,899 | 61,911 | 37,770 | |||||||||
| 8,614,826 | 12,389,750 | 9,999,752 | ||||||||||
|
OPERATING EXPENSES:
|
||||||||||||
|
Depreciation, depletion and amortization
|
||||||||||||
|
Recurring
|
2,395,063 | 2,516,437 | 2,347,791 | |||||||||
|
Additional
|
2,818,161 | 5,333,821 | — | |||||||||
|
Asset retirement obligation accretion
|
104,815 | 101,348 | 96,438 | |||||||||
|
Lease operating expenses
|
1,662,140 | 1,909,625 | 1,652,855 | |||||||||
|
Gathering and transportation
|
142,699 | 156,491 | 137,407 | |||||||||
|
Taxes other than income
|
579,436 | 984,807 | 597,647 | |||||||||
|
General and administrative
|
343,883 | 288,794 | 275,065 | |||||||||
|
Financing costs, net
|
242,238 | 166,035 | 219,937 | |||||||||
| 8,288,435 | 11,457,358 | 5,327,140 | ||||||||||
|
INCOME (LOSS) BEFORE INCOME TAXES
|
326,391 | 932,392 | 4,672,612 | |||||||||
|
Current income tax provision
|
841,899 | 1,456,382 | 970,728 | |||||||||
|
Deferred income tax provision (benefit)
|
(231,110 | ) | (1,235,944 | ) | 889,526 | |||||||
|
NET INCOME (LOSS)
|
(284,398 | ) | 711,954 | 2,812,358 | ||||||||
|
Preferred stock dividends
|
7,294 | 5,680 | 5,680 | |||||||||
|
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
|
$ | (291,692 | ) | $ | 706,274 | $ | 2,806,678 | |||||
|
NET INCOME (LOSS) PER COMMON SHARE:
|
||||||||||||
|
Basic
|
$ | (0.87 | ) | $ | 2.11 | $ | 8.45 | |||||
|
Diluted
|
$ | (0.87 | ) | $ | 2.09 | $ | 8.39 | |||||
The accompanying notes to consolidated financial statements are
an integral part of this statement.
F-4
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
STATEMENT
OF CONSOLIDATED CASH FLOWS
| For the Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net income (loss)
|
$ | (284,398 | ) | $ | 711,954 | $ | 2,812,358 | |||||
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
||||||||||||
|
Depreciation, depletion and amortization
|
5,213,224 | 7,850,258 | 2,347,791 | |||||||||
|
Asset retirement obligation accretion
|
104,815 | 101,348 | 96,438 | |||||||||
|
Provision for (benefit from) deferred income taxes
|
(231,110 | ) | (1,235,944 | ) | 889,526 | |||||||
|
Other
|
182,611 | (50,596 | ) | 48,967 | ||||||||
|
Changes in operating assets and liabilities, net of effects of
acquisitions:
|
||||||||||||
|
Receivables
|
(186,802 | ) | 570,592 | (261,962 | ) | |||||||
|
Inventories
|
(5,172 | ) | (22,295 | ) | 39,787 | |||||||
|
Drilling advances
|
(142,610 | ) | 28,846 | (30,531 | ) | |||||||
|
Deferred charges and other
|
148,113 | (323,832 | ) | 12,368 | ||||||||
|
Accounts payable
|
(180,336 | ) | (70,979 | ) | (38,923 | ) | ||||||
|
Accrued expenses
|
(330,485 | ) | (456,635 | ) | (169,087 | ) | ||||||
|
Deferred credits and noncurrent liabilities
|
(64,207 | ) | (37,373 | ) | (69,299 | ) | ||||||
|
NET CASH PROVIDED BY OPERATING ACTIVITIES
|
4,223,643 | 7,065,344 | 5,677,433 | |||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Additions to oil and gas property
|
(3,325,710 | ) | (5,143,603 | ) | (4,301,044 | ) | ||||||
|
Additions to gathering, transmission and processing facilities
|
(305,389 | ) | (679,405 | ) | (480,936 | ) | ||||||
|
Acquisition of Anadarko properties
|
— | — | (1,004,593 | ) | ||||||||
|
Acquisitions, other
|
(310,472 | ) | (149,838 | ) | (20,363 | ) | ||||||
|
Short-term investments
|
791,999 | (791,999 | ) | — | ||||||||
|
Restricted cash
|
13,880 | (13,880 | ) | — | ||||||||
|
Proceeds from sale of oil and gas properties
|
2,267 | 307,974 | 67,483 | |||||||||
|
Other, net
|
(114,001 | ) | (64,226 | ) | (206,476 | ) | ||||||
|
NET CASH USED IN INVESTING ACTIVITIES
|
(3,247,426 | ) | (6,534,977 | ) | (5,945,929 | ) | ||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
Commercial paper, credit facility and bank notes, net
|
248,169 | (99,803 | ) | (1,412,250 | ) | |||||||
|
Fixed-rate debt borrowings
|
— | 796,315 | 1,992,290 | |||||||||
|
Payments on fixed-rate notes
|
(100,000 | ) | (353 | ) | (173,000 | ) | ||||||
|
Dividends paid
|
(208,603 | ) | (239,358 | ) | (204,753 | ) | ||||||
|
Common stock activity
|
28,495 | 31,513 | 29,682 | |||||||||
|
Redemption of preferred stock
|
(98,387 | ) | — | — | ||||||||
|
Treasury stock activity, net
|
5,620 | 4,498 | 14,279 | |||||||||
|
Cost of debt and equity transactions
|
(655 | ) | (7,050 | ) | (18,179 | ) | ||||||
|
Other
|
15,811 | 39,498 | 25,726 | |||||||||
|
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
(109,550 | ) | 525,260 | 253,795 | ||||||||
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
866,667 | 1,055,627 | (14,701 | ) | ||||||||
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
1,181,450 | 125,823 | 140,524 | |||||||||
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
$ | 2,048,117 | $ | 1,181,450 | $ | 125,823 | ||||||
|
SUPPLEMENTARY CASH FLOW DATA:
|
||||||||||||
|
Interest paid, net of capitalized interest
|
$ | 243,041 | $ | 171,487 | $ | 181,138 | ||||||
|
Income taxes paid, net of refunds
|
686,411 | 1,694,557 | 797,589 | |||||||||
The accompanying notes to consolidated financial statements are
an integral part of this statement.
F-5
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEET
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (In thousands) | ||||||||
|
ASSETS
|
||||||||
|
CURRENT ASSETS:
|
||||||||
|
Cash and cash equivalents
|
$ | 2,048,117 | $ | 1,181,450 | ||||
|
Short-term investments
|
— | 791,999 | ||||||
|
Receivables, net of allowance
|
1,545,699 | 1,356,979 | ||||||
|
Inventories
|
533,251 | 498,567 | ||||||
|
Drilling advances
|
230,733 | 93,377 | ||||||
|
Prepaid taxes
|
146,653 | 303,203 | ||||||
|
Prepaid assets and other
|
81,396 | 225,399 | ||||||
| 4,585,849 | 4,450,974 | |||||||
|
PROPERTY AND EQUIPMENT:
|
||||||||
|
Oil and gas, on the basis of full-cost accounting:
|
||||||||
|
Proved properties
|
44,267,037 | 40,639,281 | ||||||
|
Unproved properties and properties under development, not being
amortized
|
1,479,008 | 1,300,347 | ||||||
|
Gathering, transmission and processing facilities
|
3,189,177 | 2,883,789 | ||||||
|
Other
|
492,511 | 452,989 | ||||||
| 49,427,733 | 45,276,406 | |||||||
|
Less: Accumulated depreciation, depletion and amortization
|
(26,527,118 | ) | (21,317,889 | ) | ||||
| 22,900,615 | 23,958,517 | |||||||
|
OTHER ASSETS:
|
||||||||
|
Restricted cash
|
— | 13,880 | ||||||
|
Goodwill, net
|
189,252 | 189,252 | ||||||
|
Deferred charges and other
|
510,027 | 573,862 | ||||||
| $ | 28,185,743 | $ | 29,186,485 | |||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
|
CURRENT LIABILITIES:
|
||||||||
|
Accounts payable
|
$ | 396,564 | $ | 548,945 | ||||
|
Accrued operating expense
|
90,151 | 168,531 | ||||||
|
Accrued exploration and development
|
923,084 | 964,859 | ||||||
|
Accrued compensation and benefits
|
151,408 | 111,907 | ||||||
|
Current debt
|
117,326 | 112,598 | ||||||
|
Asset retirement obligations
|
146,654 | 339,155 | ||||||
|
Derivative instruments
|
128,219 | — | ||||||
|
Other
|
439,152 | 274,440 | ||||||
| 2,392,558 | 2,520,435 | |||||||
|
LONG-TERM DEBT
|
4,950,390 | 4,808,975 | ||||||
|
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
|
||||||||
|
Income taxes
|
2,764,901 | 3,166,657 | ||||||
|
Asset retirement obligation
|
1,637,357 | 1,555,529 | ||||||
|
Other
|
661,916 | 626,168 | ||||||
| 5,064,174 | 5,348,354 | |||||||
|
COMMITMENTS AND CONTINGENCIES (Note 8)
SHAREHOLDERS’ EQUITY: |
||||||||
|
Preferred stock, no par value, 5,000,000 shares authorized
Series B, 5.68% Cumulative,
|
||||||||
|
$100 million aggregate liquidation value,
100,000 shares redeemed in 2009, 100,000 issued
|
||||||||
|
and outstanding in 2008
|
— | 98,387 | ||||||
|
Common stock, $0.625 par, 430,000,000 shares
authorized, 344,076,790 and
|
||||||||
|
342,754,114 shares issued, respectively
|
215,048 | 214,221 | ||||||
|
Paid-in capital
|
4,634,326 | 4,472,826 | ||||||
|
Retained earnings
|
11,436,580 | 11,929,827 | ||||||
|
Treasury stock, at cost, 7,639,818 and 8,044,050 shares,
respectively
|
(216,831 | ) | (228,304 | ) | ||||
|
Accumulated other comprehensive income (loss)
|
(290,502 | ) | 21,764 | |||||
| 15,778,621 | 16,508,721 | |||||||
| $ | 28,185,743 | $ | 29,186,485 | |||||
The accompanying notes to consolidated financial statements are
an integral part of this statement.
F-6
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED SHAREHOLDERS’ EQUITY
|
Accumulated
|
|||||||||||||||||||||||||||||||||
|
Series B
|
Other
|
Total
|
|||||||||||||||||||||||||||||||
|
Comprehensive
|
Preferred
|
Common
|
Paid-In
|
Retained
|
Treasury
|
Comprehensive
|
Shareholders’
|
||||||||||||||||||||||||||
| Income (Loss) | Stock | Stock | Capital | Earnings | Stock | Income (Loss) | Equity | ||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||
|
BALANCE AT DECEMBER 31, 2006
|
$ | 98,387 | $ | 212,365 | $ | 4,269,795 | $ | 8,898,577 | $ | (256,739 | ) | $ | (31,332 | ) | $ | 13,191,053 | |||||||||||||||||
|
Comprehensive income:
|
|||||||||||||||||||||||||||||||||
|
Net income
|
$ | 2,812,358 | — | — | — | 2,812,358 | — | — | 2,812,358 | ||||||||||||||||||||||||
|
Post retirement, net of income tax
|
|||||||||||||||||||||||||||||||||
|
expense of $4,896
|
6,333 | — | — | — | — | — | 6,333 | 6,333 | |||||||||||||||||||||||||
|
Commodity hedges, net of income tax
|
|||||||||||||||||||||||||||||||||
|
benefit of $272,865
|
(495,212 | ) | — | — | — | — | — | (495,212 | ) | (495,212 | ) | ||||||||||||||||||||||
|
Comprehensive income
|
$ | 2,323,479 | |||||||||||||||||||||||||||||||
|
Cash dividends:
|
|||||||||||||||||||||||||||||||||
|
Preferred
|
— | — | — | (5,680 | ) | — | — | (5,680 | ) | ||||||||||||||||||||||||
|
Common ($.60 per share)
|
— | — | — | (199,401 | ) | — | — | (199,401 | ) | ||||||||||||||||||||||||
|
Common shares issued
|
— | 961 | 48,144 | — | — | — | 49,105 | ||||||||||||||||||||||||||
|
Treasury shares issued, net
|
— | — | 1,834 | — | 18,475 | — | 20,309 | ||||||||||||||||||||||||||
|
Compensation expense
|
— | — | 48,816 | — | — | — | 48,816 | ||||||||||||||||||||||||||
|
Tax reserves
|
— | — | — | (48,502 | ) | — | — | (48,502 | ) | ||||||||||||||||||||||||
|
Other
|
— | — | (1,440 | ) | 240 | — | — | (1,200 | ) | ||||||||||||||||||||||||
|
BALANCE AT DECEMBER 31, 2007
|
98,387 | 213,326 | 4,367,149 | 11,457,592 | (238,264 | ) | (520,211 | ) | 15,377,979 | ||||||||||||||||||||||||
|
Comprehensive income:
|
|||||||||||||||||||||||||||||||||
|
Net income
|
$ | 711,954 | — | — | — | 711,954 | — | — | 711,954 | ||||||||||||||||||||||||
|
Post retirement, net of income tax
|
|||||||||||||||||||||||||||||||||
|
benefit of $7,495
|
(7,530 | ) | — | — | — | — | — | (7,530 | ) | (7,530 | ) | ||||||||||||||||||||||
|
Commodity hedges, net of income tax
|
|||||||||||||||||||||||||||||||||
|
expense of $301,157
|
549,505 | — | — | — | — | — | 549,505 | 549,505 | |||||||||||||||||||||||||
|
Comprehensive income
|
$ | 1,253,929 | |||||||||||||||||||||||||||||||
|
Cash dividends:
|
|||||||||||||||||||||||||||||||||
|
Preferred
|
— | — | — | (5,680 | ) | — | — | (5,680 | ) | ||||||||||||||||||||||||
|
Common ($.70 per share)
|
— | — | — | (233,952 | ) | — | — | (233,952 | ) | ||||||||||||||||||||||||
|
Common shares issued
|
— | 895 | 36,722 | — | — | — | 37,617 | ||||||||||||||||||||||||||
|
Treasury shares issued, net
|
— | — | (442 | ) | — | 9,960 | — | 9,518 | |||||||||||||||||||||||||
|
Compensation expense
|
— | — | 93,762 | — | — | — | 93,762 | ||||||||||||||||||||||||||
|
Tax reserves
|
— | — | (23,663 | ) | — | — | — | (23,663 | ) | ||||||||||||||||||||||||
|
Other
|
— | — | (702 | ) | (87 | ) | — | — | (789 | ) | |||||||||||||||||||||||
|
BALANCE AT DECEMBER 31, 2008
|
98,387 | 214,221 | 4,472,826 | 11,929,827 | (228,304 | ) | 21,764 | 16,508,721 | |||||||||||||||||||||||||
|
Comprehensive loss:
|
|||||||||||||||||||||||||||||||||
|
Net loss
|
$ | (284,398 | ) | — | — | — | (284,398 | ) | — | — | (284,398 | ) | |||||||||||||||||||||
|
Post retirement, net of income tax
|
|||||||||||||||||||||||||||||||||
|
benefit of $4,754
|
(4,533 | ) | — | — | — | — | — | (4,533 | ) | (4,533 | ) | ||||||||||||||||||||||
|
Commodity hedges, net of income tax
|
|||||||||||||||||||||||||||||||||
|
benefit of $171,310
|
(307,733 | ) | — | — | — | — | — | (307,733 | ) | (307,733 | ) | ||||||||||||||||||||||
|
Comprehensive loss
|
$ | (596,664 | ) | ||||||||||||||||||||||||||||||
|
Cash dividends:
|
|||||||||||||||||||||||||||||||||
|
Preferred
|
— | — | — | (7,294 | ) | — | — | (7,294 | ) | ||||||||||||||||||||||||
|
Common ($.60 per share)
|
— | — | — | (201,555 | ) | — | — | (201,555 | ) | ||||||||||||||||||||||||
|
Preferred stock redemption
|
(98,387 | ) | — | — | — | — | — | (98,387 | ) | ||||||||||||||||||||||||
|
Common shares issued
|
— | 827 | 14,916 | — | — | — | 15,743 | ||||||||||||||||||||||||||
|
Treasury shares issued, net
|
— | — | (5,262 | ) | — | 11,473 | — | 6,211 | |||||||||||||||||||||||||
|
Compensation expense
|
— | — | 128,523 | — | — | — | 128,523 | ||||||||||||||||||||||||||
|
Tax reserves
|
— | — | 23,695 | — | — | — | 23,695 | ||||||||||||||||||||||||||
|
Other
|
— | — | (372 | ) | — | — | — | (372 | ) | ||||||||||||||||||||||||
|
BALANCE AT DECEMBER 31, 2009
|
$ | — | $ | 215,048 | $ | 4,634,326 | $ | 11,436,580 | $ | (216,831 | ) | $ | (290,502 | ) | $ | 15,778,621 | |||||||||||||||||
The accompanying notes to consolidated financial statements are
an integral part of this statement.
F-7
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
Nature
of Operations
Apache Corporation (Apache or the Company) is an independent
energy company that explores for, develops and produces natural
gas, crude oil and natural gas liquids. The Company’s North
American exploration and production activities are divided into
two United States (U.S.) operating regions (Central and Gulf
Coast) and a Canadian region. Approximately 62 percent
(unaudited) of the Company’s proved reserves are located in
North America. Outside of North America, Apache has exploration
and production interests in Egypt, offshore Western Australia,
offshore the United Kingdom in the North Sea (North Sea) and
Argentina. Apache also has exploration interests 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
the 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 Company consolidates
all investments in which the Company, either through direct or
indirect ownership, has more than a 50-percent voting interest.
In addition, Apache consolidates all variable interest entities
where it is the primary beneficiary. The Company’s interest
in oil and gas exploration and production ventures and
partnerships are proportionately consolidated.
Use of
Estimates
Preparation of financial statements in conformity with GAAP
requires management to make estimates and assumptions that
affect reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities at the date of the
financial statements, and the reported amounts of revenues and
expenses during the reporting period. 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 with regard to these financial
statements include the estimate of proved oil and gas reserves
and related present value estimates of future net cash flows
therefrom (see Note 13 — Supplemental Oil and Gas
Disclosures), asset retirement obligations and income taxes.
Cash
Equivalents
The Company considers all highly liquid short-term investments
with a maturity of three months or less at time of purchase to
be cash equivalents. These investments are carried at cost,
which approximates fair value. As of December 31, 2009 and
2008, Apache had $2.0 billion and $1.2 billion,
respectively, of cash and cash equivalents.
Marketable
Securities
The Company accounts for investments in debt and equity
securities in accordance with the Financial Accounting Standards
Board (FASB) Accounting Standards Codification (ASC, also known
collectively as the Codification) Topic 320,
“Investments — Debt and Equity Securities.”
Investments in debt securities classified as “held to
maturity” are recorded at cost. As of December 31,
2009, Apache held no marketable securities. At December 31,
2008, the Company had $792 million invested in obligations
of the U.S. government with original maturities greater
than three months but less than a year.
F-8
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Allowance
for Doubtful Accounts
The Company routinely assesses the collectibility of all
material trade and other receivables. Many of Apache’s
receivables are from joint interest owners on properties Apache
operates. Thus, Apache may have the ability to withhold future
revenue disbursements to recover any non-payment of these joint
interest billings. Generally, the Company’s crude oil and
natural gas receivables are collected within two months. 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, 2009 and 2008, the Company
had an allowance for doubtful accounts of $38 million and
$33 million, respectively.
While Apache experienced a decline in the timeliness of receipts
from the Egyptian General Petroleum Corporation (EGPC) for oil
and gas sales in recent years, the Company saw significant
improvement in collections throughout 2009.
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 $219 million,
$236 million and $208 million of these internal costs
in 2009, 2008 and 2007, 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 Company’s reserve
quantities in a particular country are sold, in which case a
gain or loss is recognized in income.
In December 2007 the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards (SFAS)
No. 141 (Revised), “Business Combinations”
(SFAS No. 141(R)), which was amended by FASB Staff
Position (FSP) FAS No. 141(R)-1 in April 2009. This
guidance has been primarily codified into the FASB Accounting
Standards Codification (ASC, also known collectively as the
Codification) Topic 805, “Business Combinations.” The
guidance broadens the definition of a business combination to
include all transactions or other events in which control of one
or more businesses is obtained. Further, the standard
establishes principles and requirements for how an acquirer
recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, any
non-controlling interests in the acquiree and the goodwill
acquired. The statement requires the acquiring entity in a
business combination to recognize the fair value of all the
assets acquired and liabilities assumed in the transaction. It
also modifies disclosure requirements. Apache adopted this
statement effective January 1, 2009. However, since the
Company did not close any material business combinations during
the 2009, the adoption had a negligible impact on the
Company’s consolidated financial statements.
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
F-9
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 (G&G) 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. In January 2009, the SEC issued Release
No. 33-8995,
“Modernization of Oil and Gas Reporting” (Release
33-8995),
amending oil and gas reporting requirements under
Rule 4-10
of
Regulation S-X
and Industry Guide 2 in
Regulation S-K
and bringing full-cost accounting rules into alignment with the
revised disclosure requirements. In January 2010, the FASB
issued Accounting Standards Update (ASU)
No. 2010-03,
“Oil and Gas Reserve Estimation and Disclosures” (ASU
2010-03),
which amends ASC Topic 932, “Extractive
Industries — Oil and Gas” (ASC Topic 932) to
align the guidance with the changes made by the SEC. The Company
adopted Release
33-8995
and
the amendments to ASC Topic 932 resulting from ASU
2010-03
(collectively, the Modernization Rules) effective
December 31, 2009.
The estimate of after-tax future net cash flows as of
December 31, 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 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. If capitalized
costs exceed this ceiling, the excess is charged to expense and
reflected as additional DD&A. Excluding the effect of cash
flow hedges in calculating the ceiling limitation at
December 31, 2009, capitalized costs still would not have
exceeded the ceiling limitation. See Note 13 —
Supplemental Oil and Gas Disclosures for a discussion on
calculation of estimated future net cash flows.
Under the 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 Company’s
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 Company’s U.S. and Canadian
proved oil and gas properties on 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
F-10
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
and processing facilities totaled $3.2 billion and
$2.9 billion at December 31, 2009 and 2008,
respectively. No impairment of gathering, transmission and
processing facilities was recognized during 2009, 2008 or 2007.
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 simplest terms, multiplies the percentage of
estimated proved reserves produced each quarter times the costs
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 which 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 billion and $870 million at December 31, 2009
and 2008, 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 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 exploration and development activities that are
in progress. 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 Company’s 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. As major construction projects are
completed, the associated capitalized interest is amortized over
the useful life of the related asset. Capitalized interest
totaled $61 million, $94 million and $76 million
in 2009, 2008 and 2007, respectively.
Goodwill
Goodwill represents the excess of the purchase price of an
entity over the estimated fair value of the assets acquired and
liabilities assumed. 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 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 $189 million at December 31, 2009 and
2008, with approximately $103 million and $86 million
recorded in Canada and Egypt, respectively. Each country was
assessed as a reporting unit. No impairment of goodwill was
recognized during 2009, 2008 or 2007.
F-11
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Accounts
Payable
Included in accounts payable at December 31, 2009 and 2008,
are liabilities of approximately $98 million and
$164 million, respectively, representing the amount by
which checks issued, but not presented to the Company’s
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 Company’s 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. As the
Company’s production fluctuates because of operational
issues, it is occasionally necessary to purchase gas
(third-party gas) to fulfill its 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 $34 million,
$56 million and $123 million, for 2009, 2008 and 2007,
respectively.
The Company’s 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. The balance of the production is split among the
contractor partners and the EGPC on a contractually defined
basis. Cost recovery is reflected in revenue.
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 (which is generally based on information obtained
from an independent investment banking firm). 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 Company’s oil and gas cash flow hedges, including
terminated contracts, are generally recognized in oil and gas
F-12
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 our financial statements and our 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 portion 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).
Earnings from Apache’s 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 has been determined to be the functional
currency for each of Apache’s 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
2009, the Company recorded additional net tax expense of
$195 million, including a current tax benefit of
$3 million and deferred tax expense of $198 million,
in connection with foreign currency translation gains and
losses. 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. In
2007, the Company recorded additional deferred tax expense of
$228 million. Foreign currency translation gains and losses
had a negligible impact on current tax expense in 2007. 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 Company’s other
foreign currency gains and losses included in “Other”
under Revenues and Other in the Statement of Consolidated
Operations netted to gains of $11 million, $38 million
and $9 million in 2009, 2008 and 2007, respectively.
F-13
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Foreign currency gains and losses also arise when revenue and
disbursement transactions denominated in a country’s 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 Company’s 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 the 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
Company’s stock at the end of the reporting period exceeded
the share price goals under the terms of the plan.
Unvested share-based payment awards that contain rights to
receive nonforfeitable dividends or dividend equivalents are
participating securities prior to vesting and, therefore, are
included in the earnings allocations in computing basic EPS
under the two-class method.
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 $16 million, $47 million and
$30 million as financing cash inflows in 2009, 2008 and
2007, 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, 2009.
F-14
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 2. | SIGNIFICANT ACQUISITIONS AND DIVESTITURES |
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 barrels of oil equivalent
per day 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 (unaudited). These long-lived fields fit well
with Apache’s existing properties in the Permian Basin,
particularly in Lea County, N.M., 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. These
divestitures were subject to normal post-closing adjustments.
2007
Activity
U.S. Gulf Coast Farm-in
On
September 6, 2007, Apache entered into an Exploration
Agreement with various EnerVest Partnerships (“EVP”)
for an initial term of four years whereby Apache committed to
spend $30 million in qualified expenditures to explore,
drill, produce and market hydrocarbons from specified
undeveloped formations across 400,000 net acres in Central
and East Texas. As of December 31, 2008, Apache had
fulfilled the $30 million commitment.
U.S. Permian Basin
On March 29,
2007, the Company closed its acquisition of controlling interest
in 28 oil and gas fields in the Permian Basin of West Texas from
Anadarko for $1 billion. Apache estimates that these fields
had proved reserves of 57 million barrels (MMbbls)
(unaudited) of liquid hydrocarbons and 78 billion cubic
feet (Bcf) (unaudited) of natural gas as of year-end 2006. The
Company funded the acquisition with debt. Apache and Anadarko
entered into a joint-venture arrangement to effect the
transaction. The Company entered into cash flow hedges for a
portion of the crude oil and natural gas production.
| 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.
Apache’s first strategy is to maintain a balance in its
commodities mix of oil and gas, and gas sold at New York
Mercantile Exchange (NYMEX)-related prices versus gas sold under
long-term contracts tied to oil prices. Management also believes
it is prudent to manage the variability in cash flows 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 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. Apache’s commodity
derivative instruments are with a diversified group of
counterparties, primarily financial institutions. To reduce the
concentration of exposure to any
F-15
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
individual counterparty, Apache had positions with 16
counterparties as of December 31, 2009. All of these
counterparties were at year-end rated A or higher by
Standard & Poor’s and A2 or higher by
Moody’s. 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 under
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 will have the right to demand the posting of
collateral, demand a transfer or terminate the arrangement.
Commodity
Derivative Instruments
As of December 31, 2009, 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) | |||||||||||||||
|
2010
|
2,383 | $ | 68.71 | 10,396 | $ | 65.01 | $ | 80.84 | ||||||||||||
|
2011
|
3,650 | 70.12 | 6,202 | 66.24 | 87.04 | |||||||||||||||
|
2012
|
3,292 | 70.99 | 2,554 | 66.07 | 89.13 | |||||||||||||||
|
2013
|
1,451 | 72.01 | — | — | — | |||||||||||||||
|
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. |
As of December 31, 2009, 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 000’s) | (in 000’s) | Price(1) | (in 000’s) | (in 000’s) | Floor Price(1) | Ceiling Price(1) | |||||||||||||||||||||
|
2010
|
82,125 | — | $ | 5.81 | 30,550 | — | $ | 5.48 | $ | 7.07 | ||||||||||||||||||
|
2010
|
— | 54,750 | 5.37 | — | — | — | — | |||||||||||||||||||||
|
2011
|
10,038 | — | 6.61 | 9,125 | — | 5.00 | 8.85 | |||||||||||||||||||||
|
2011
|
— | 23,725 | 6.75 | — | 3,650 | 6.50 | 7.10 | |||||||||||||||||||||
|
2012
|
2,745 | — | 6.73 | 10,980 | — | 5.75 | 8.43 | |||||||||||||||||||||
|
2012
|
— | 29,280 | 6.95 | — | 7,320 | 6.50 | 7.27 | |||||||||||||||||||||
|
2013
|
1,825 | — | 7.05 | — | — | — | — | |||||||||||||||||||||
|
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 natural gas prices represent a weighted average of AECO Index prices. The Canadian gas contracts are entered into on a per gigajoule (GJ) basis and are settled against AECO Index. These Canadian gas contracts are shown in Canadian dollars. |
F-16
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
As of December 31, 2009, Apache had the following open
natural gas financial basis swap contracts:
|
Weighted
|
||||||||
|
MMBtu
|
Average
|
|||||||
|
Production Period
|
(in 000’s) | Price Differential(1) | ||||||
|
2010
|
41,975 | $ | (0.54 | ) | ||||
| (1) | Natural gas financial basis swap contracts represent a weighted average differential between prices primarily at Inside FERC PEPL and NYMEX Henry Hub prices. |
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 counterparty master netting
arrangements contain provisions for net settlement. The fair
market value of the Company’s derivative assets and
liabilities are as follows:
|
December 31,
|
December 31,
|
|||||||
| 2009 | 2008 | |||||||
| (In millions) | ||||||||
|
Current Assets: Prepaid assets and other
|
$ | 13 | $ | 154 | ||||
|
Other Assets: Deferred charges and other
|
51 | 65 | ||||||
|
Total Assets
|
$ | 64 | $ | 219 | ||||
|
Current Liabilities: Derivative instruments
|
$ | 128 | $ | — | ||||
|
Noncurrent Liabilities: Other
|
202 | 7 | ||||||
|
Total Liabilities
|
$ | 330 | $ | 7 | ||||
The methods and assumptions used to estimate the fair values of
the Company’s commodity derivative instruments and gross
amounts of commodity derivative assets and liabilities are more
fully discussed in Note 10 — Fair Value
Measurements.
Commodity
Derivative Activity Recorded in Statement of Consolidated
Operations
The following table summarizes the effect of derivative
instruments on the Company’s Statement of Consolidated
Operations:
|
For the Year Ended
|
||||||||||||||
|
Gain (Loss) on Derivatives
|
December 31, | |||||||||||||
| Recognized in Operations | 2009 | 2008 | 2007 | |||||||||||
| (In millions) | ||||||||||||||
|
Gain (loss) reclassified from accumulated other comprehensive
income (loss) into operations (effective portion)
|
Oil and Gas Production Revenues | $ | 176 | $ | (431 | ) | $ | (31 | ) | |||||
|
Gain (loss) on derivatives recognized in operations (ineffective
portion and basis)
|
Revenues and Other: Other | $ | 2 | $ | (1 | ) | $ | — | ||||||
Commodity
Derivative Activity in Accumulated Other Comprehensive Income
(Loss
)
As of December 31, 2009, the Company’s derivative
instruments were designated as cash flow hedges in accordance
with ASC Topic 815. A reconciliation of the components of
accumulated other comprehensive income
F-17
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
(loss) in the Statement of Consolidated Shareholders’
Equity related to Apache’s cash flow hedges is presented in
the table below:
| 2009 | 2008 | 2007 | ||||||||||||||||||||||
| Before tax | After tax | Before tax | After tax | Before tax | After tax | |||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
|
Unrealized gain (loss) on derivatives at beginning of year
|
$ | 212 | $ | 138 | $ | (639 | ) | $ | (412 | ) | $ | 129 | $ | 84 | ||||||||||
|
Realized amounts reclassified into earnings
|
(176 | ) | (120 | ) | 431 | 279 | 31 | 18 | ||||||||||||||||
|
Net change in derivative fair value
|
(302 | ) | (187 | ) | 419 | 270 | (799 | ) | (514 | ) | ||||||||||||||
|
Ineffectiveness and basis swaps reclassified into earnings
|
(2 | ) | (1 | ) | 1 | 1 | — | — | ||||||||||||||||
|
Unrealized gain (loss) on derivatives at end of year
|
$ | (268 | ) | $ | (170 | ) | $ | 212 | $ | 138 | $ | (639 | ) | $ | (412 | ) | ||||||||
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
income (loss) as of December 31, 2009 is a net loss of
approximately $117 million ($76 million after tax)
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 Company’s ARO
liability for the years ended December 31, 2009 and 2008:
| 2009 | 2008 | |||||||
| (In thousands) | ||||||||
|
Asset retirement obligation at beginning of year
|
$ | 1,894,684 | $ | 1,866,686 | ||||
|
Liabilities incurred
|
218,423 | 343,210 | ||||||
|
Liabilities settled
|
(508,426 | ) | (587,246 | ) | ||||
|
Accretion expense
|
104,815 | 101,348 | ||||||
|
Revisions in estimated liabilities
|
74,515 | 170,686 | ||||||
|
Asset retirement obligation at end of year
|
1,784,011 | 1,894,684 | ||||||
|
Less current portion
|
146,654 | 339,155 | ||||||
|
Asset retirement obligation, long-term
|
$ | 1,637,357 | $ | 1,555,529 | ||||
The ARO liability reflects the estimated present value of the
amount of dismantlement, removal, site reclamation and similar
activities associated with Apache’s 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.
Liabilities settled primarily relate to individual properties
plugged and abandoned during the period. Most of the activity in
both periods was in the Gulf of Mexico, a portion of which
relates to the continued abandonment activity on platforms
toppled in 2005 during Hurricanes Katrina and Rita and in 2008
during Hurricane Ike.
F-18
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 5. | DEBT |
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (In millions) | ||||||||
|
U.S.:
|
||||||||
|
Money market lines of credit
|
$ | — | $ | — | ||||
|
Unsecured committed bank credit facilities
|
— | — | ||||||
|
Commercial paper
|
— | — | ||||||
|
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 | ||||||
|
7.7% notes due 2026
|
100 | 100 | ||||||
|
7.95% notes due 2026
|
180 | 180 | ||||||
|
6.0% notes due 2037
|
1,000 | 1,000 | ||||||
|
7.375% debentures due 2047
|
150 | 150 | ||||||
|
7.625% debentures due 2096
|
150 | 150 | ||||||
| 4,080 | 4,080 | |||||||
|
Subsidiary and other obligations:
|
||||||||
|
Argentina overdraft lines of credit
|
7 | 13 | ||||||
|
Apache PVG secured facility
|
350 | 100 | ||||||
|
Notes due in 2016 and 2017
|
1 | 1 | ||||||
|
Apache Finance Australia 7.0% notes redeemed in 2009
|
— | 100 | ||||||
|
Apache Finance Canada 4.375% notes due 2015
|
350 | 350 | ||||||
|
Apache Finance Canada 7.75% notes due 2029
|
300 | 300 | ||||||
| 1,008 | 864 | |||||||
|
Debt at face value
|
5,088 | 4,944 | ||||||
|
Unamortized discount
|
(21 | ) | (22 | ) | ||||
|
Total debt
|
5,067 | 4,922 | ||||||
|
Current maturities
|
(117 | ) | (113 | ) | ||||
|
Long-term debt
|
$ | 4,950 | $ | 4,809 | ||||
F-19
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Debt maturities as of December 31, 2009, excluding
discounts, are as follows:
| (In millions) | ||||
|
2010
|
$ | 117 | ||
|
2011
|
100 | |||
|
2012
|
480 | |||
|
2013
|
945 | |||
|
2014
|
15 | |||
|
Thereafter
|
3,431 | |||
|
Total Debt, excluding discounts
|
$ | 5,088 | ||
Overview
All of the Company’s debt, excluding the Apache PVG secured
facility, 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 Apache’s
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
pre-payment 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, 2009 and 2008,
$7.3 million and $12.6 million, respectively, was
drawn on facilities in Argentina.
Unsecured
Committed Bank Credit Facilities
As of December 31, 2009, the Company had unsecured
committed revolving syndicated bank credit facilities totaling
$2.3 billion, which mature in May 2013. The facilities
consist of 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. Since there are no
outstanding borrowings or commercial paper at year-end, the full
$2.3 billion of unsecured credit facilities are available
to the Company. The U.S. credit facilities are used to
support Apache’s 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 Company’s
debt-to-capitalization
ratio at December 31, 2009 was 24 percent.
The negative covenants include restrictions on the
Company’s 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 Company’s consolidated
assets, or approximately $1.4 billion as of
December 31, 2009. There are no restrictions on incurring
liens in countries other than the U.S. and Canada. There
are also restrictions on Apache’s 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 (MAC clauses). 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
F-20
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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, 2009.
At the Company’s option, the interest rate for the
facilities is based on (i) the greater of (a) the JP
Morgan Chase Bank prime rate or (b) the federal funds rate
plus one-half of one percent or (ii) the London Inter-bank
Offered Rate (LIBOR) plus a margin determined by the
Company’s senior long-term debt rating. The
$1.5 billion and the $450 million credit facilities
(U.S. credit facilities) also allow the company to borrow
under competitive auctions.
At December 31, 2009, the margin over LIBOR for committed
loans was .19 percent on the $1.5 billion facility and
.23 percent on the other three facilities. 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
Company’s senior long-term debt rating.
Commercial
Paper Program
The Company has available a $1.95 billion commercial paper
program, which generally enables Apache to borrow funds for up
to 270 days at competitive interest rates. If the Company
is unable to issue commercial paper following a significant
credit downgrade or dislocation in the market, the
Company’s 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 2013. As
of December 31, 2009 and 2008, the Company had no
outstanding commercial paper.
U.S. Debt
The U.S. 6.25-percent, 5.25-percent, 5.625-percent,
6.9-percent and both 6.0-percent notes are redeemable, as a
whole or in part, at Apache’s 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 and Credit Facility
Rule 3-10
of SEC
Regulation S-X
(Rule 3-10)
generally requires filing of financial statements by every
issuer of a registered security. Issuers with no independent
operations qualify as “finance subsidiaries” and are
exempt from the reporting requirements. Apache Finance Australia
and Apache Finance Canada qualified as “finance
subsidiaries” until Apache, during 2001, contributed stock
of its Australian and Canadian operating subsidiaries to Apache
Finance Australia and Apache Finance Canada, respectively.
Apache Finance Australia
Apache Finance
Pty Limited (Apache Finance Australia) issued approximately
$270 million of publicly-traded notes that were fully and
unconditionally guaranteed by Apache and, beginning in 2001,
also by Apache North America, Inc. 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 Corporation (Apache Finance Canada) issued approximately
$300 million of 7.75-percent publicly-traded notes due in
2029 and an additional $350 million of 4.375-percent
publicly-traded notes due in 2015 that are fully and
unconditionally guaranteed by Apache. Under certain conditions
related to changes in relevant tax laws, Apache Finance Canada
has the right to redeem either of the
F-21
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
notes prior to maturity. The Apache Finance Canada 4.375-percent
notes also may be redeemed as a whole or in part at the
Company’s option subject to a make-whole premium.
See Note 15 — Supplemental Guarantor Information
for further discussion of subsidiary debt.
One of the Company’s Australian subsidiaries has a secured
revolving syndicated credit facility for its Van Gogh and
Pyrenees oil developments offshore Western Australia. The
facility provides for total commitments of up to
$350 million, with availability determined by a borrowing
base formula. The borrowing base was set at $350 million
and will be redetermined after the fields commence production in
the first half of 2010 and certain tests have been met, and
semi-annually thereafter. The facility is secured by certain
assets associated with the Van Gogh and Pyrenees oil
developments, including the shares of stock of the
Company’s subsidiary holding the assets. The Company has
agreed to guarantee the credit facility until project completion
occurs pursuant to terms of the facility, which is expected in
the fourth quarter of 2010. In the event project completion does
not occur by December 31, 2010, pursuant to terms of the
facility, the lenders may require repayment of outstanding
amounts in the first quarter of 2011. The commitments under the
facility will be reduced by scheduled increments every six
months beginning June 30, 2010, with final maturity on
March 31, 2014. Interest is based on LIBOR, which may be
subject to change under certain market disruption conditions,
plus a margin of 1.00 percent pre-completion and
1.75 percent post-completion. The pre-completion margin
increases to 1.125 percent in the event the Company’s
ratings are downgraded to BBB+ or below by at least two major
rating agencies. As of December 31, 2009 and 2008, there
was $350 million and $100 million, respectively,
outstanding under the facility. The outstanding amount under
this facility must not exceed $300 million on June 30,
2010 and $240 million on December 31, 2010. As
$50 million and $60 million of the current balance
will be repaid by June 30, 2010 and December 31, 2010,
respectively, $110 million has been classified as current
debt at December 31, 2009.
Credit
Ratings
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, reserve mix and
commodity pricing levels could also be considered by the rating
agencies. Apache’s senior unsecured long-term debt is
currently rated A3 by Moody’s, A- by Standard &
Poor’s and A- by Fitch. The Company has received short-term
debt ratings for its commercial paper program of
P-2
from
Moody’s,
A-2
from
Standard & Poor’s and F2 from Fitch. In September
2009 Fitch downgraded Apache’s senior unsecured long-term
debt and short-term debt from A and F1 to A- and F2,
respectively. The current outlook at all three rating agencies
is stable.
Financing Costs, Net
Financing costs incurred during the periods are composed of the
following:
| For the Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
|
Interest expense
|
$ | 309,619 | $ | 280,457 | $ | 308,235 | ||||||
|
Amortization of deferred loan costs
|
5,553 | 3,689 | 3,310 | |||||||||
|
Capitalized interest
|
(60,553 | ) | (94,164 | ) | (75,748 | ) | ||||||
|
Interest Income
|
(12,381 | ) | (23,947 | ) | (15,860 | ) | ||||||
|
Financing Costs
|
$ | 242,238 | $ | 166,035 | $ | 219,937 | ||||||
The Company has $21 million of debt discounts as of
December 31, 2009, which will be charged to interest
expense over the life of the related debt issuances;
$1.4 million, $1.1 million and $1.0 million was
recognized in 2009, 2008 and 2007, respectively.
F-22
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
As of December 31, 2009 and 2008, the Company had
approximately $40 million and $45 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.
| 6. | INCOME TAXES |
Income before income taxes is composed of the following:
| For the Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
|
United States
|
$ | (566,519 | ) | $ | (349,405 | ) | $ | 1,728,441 | ||||
|
Foreign
|
892,910 | 1,281,797 | 2,944,171 | |||||||||
|
Total
|
$ | 326,391 | $ | 932,392 | $ | 4,672,612 | ||||||
The total provision for income taxes consists of the following:
| For the Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
|
Current taxes:
|
||||||||||||
|
Federal
|
$ | (130,454 | ) | $ | 127,801 | $ | 133,140 | |||||
|
State
|
(1,964 | ) | 1,613 | 5,162 | ||||||||
|
Foreign
|
974,317 | 1,326,968 | 832,426 | |||||||||
| 841,899 | 1,456,382 | 970,728 | ||||||||||
|
Deferred taxes:
|
||||||||||||
|
Federal
|
(80,690 | ) | (413,731 | ) | 435,276 | |||||||
|
State
|
(23,603 | ) | 3,014 | (1,073 | ) | |||||||
|
Foreign
|
(126,817 | ) | (825,227 | ) | 455,323 | |||||||
| (231,110 | ) | (1,235,944 | ) | 889,526 | ||||||||
|
Total
|
$ | 610,789 | $ | 220,438 | $ | 1,860,254 | ||||||
F-23
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
A reconciliation of the tax on the Company’s income before
income taxes and total tax expense is shown below:
| For the Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
|
Income tax expense at U.S. statutory rate
|
$ | 114,237 | $ | 326,337 | $ | 1,635,414 | ||||||
|
State income tax, less federal benefit
|
(16,618 | ) | 3,008 | 2,658 | ||||||||
|
Taxes related to foreign operations
|
309,960 | 429,782 | 127,614 | |||||||||
|
Tax credits
|
(38,949 | ) | — | — | ||||||||
|
Canadian tax rate reduction
|
— | — | (145,398 | ) | ||||||||
|
Current and deferred taxes related to currency fluctuations
|
194,967 | (399,973 | ) | 227,671 | ||||||||
|
Domestic manufacturing deduction
|
— | (7,312 | ) | (6,656 | ) | |||||||
|
Net change in tax contingencies
|
35,744 | (139,590 | ) | — | ||||||||
|
Increase in valuation allowance
|
20,034 | 2,924 | 12,144 | |||||||||
|
All other, net
|
(8,586 | ) | 5,262 | 6,807 | ||||||||
| $ | 610,789 | $ | 220,438 | $ | 1,860,254 | |||||||
The net deferred tax liability consists of the following:
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (In thousands) | ||||||||
|
Deferred tax assets:
|
||||||||
|
Deferred income
|
$ | (20,408 | ) | $ | (18,327 | ) | ||
|
State net operating loss carryforwards
|
(34,516 | ) | (14,420 | ) | ||||
|
Foreign net operating loss carryforwards
|
(225,231 | ) | (127,393 | ) | ||||
|
Tax credits
|
(229,135 | ) | (322,351 | ) | ||||
|
Accrued expenses and liabilities
|
(105,066 | ) | (80,684 | ) | ||||
|
Other
|
(60,089 | ) | (97,282 | ) | ||||
|
Total deferred tax assets
|
(674,445 | ) | (660,457 | ) | ||||
|
Valuation allowance
|
35,102 | 15,068 | ||||||
|
Net deferred tax assets
|
(639,343 | ) | (645,389 | ) | ||||
|
Deferred tax liabilities:
|
||||||||
|
Depreciation, depletion and amortization
|
3,249,363 | 3,577,990 | ||||||
|
Total deferred tax liabilities
|
3,249,363 | 3,577,990 | ||||||
|
Net deferred income tax liability
|
$ | 2,610,020 | $ | 2,932,601 | ||||
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, 2009, the undistributed earnings of the
foreign subsidiaries amounted to approximately
$15.3 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.
F-24
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
On December 31, 2009, the Company had U.S. net
operating losses of $393 million, state net operating loss
carryforwards of $673 million and foreign net operating
loss carryforwards of $4 million in Canada,
$22 million in Argentina and $662 million in
Australia. The Company also had $141 million of capital
loss carryforwards in Canada. Under the provisions of the
Worker, Homeownership, and Business Assistance Act of 2009, the
Company expects to carryback the U.S. net operating loss
generated in 2009 to the 2004 tax year. 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, the Argentina net operating loss
will begin to expire in 2011, and the Australia net operating
loss has an indefinite carryover period. The capital loss in
Canada also has an indefinite carryover period.
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 the Canadian capital losses and certain 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.
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:
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
|
Balance at beginning of year
|
$ | 213,235 | $ | 508,475 | $ | 472,162 | ||||||
|
Additions based on tax positions related to the current year
|
23,373 | — | 28,461 | |||||||||
|
Additions for tax positions of prior years
|
77,272 | 48,131 | 8,376 | |||||||||
|
Reductions for tax positions of prior years
|
(92,248 | ) | (337,334 | ) | (524 | ) | ||||||
|
Settlements
|
(98,546 | ) | (6,037 | ) | — | |||||||
|
Balance at end of year
|
$ | 123,086 | $ | 213,235 | $ | 508,475 | ||||||
Included in the balance at December 31, 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 in income tax expense. Each quarter
the company assesses the amounts provided for and may increase
(expense) or reduce (benefit) the amount of interest and
penalties. During the years ended December 31, 2009 and
2008, the Company recorded tax benefits of approximately
$17 million and $87 million, respectively. In 2007,
the company recorded an additional $43 million in interest
and penalties. As of December 31, 2009 and 2008, the
Company had approximately $24 million and $41 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 audit in various
states and in most of the Company’s foreign jurisdictions
as part of its normal course of business. Resolution of any of
the above, which may occur in 2010, could result in a
significant change to the Company’s tax reserves. However,
the resolution of unagreed tax issues in the Company’s 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.
F-25
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Apache and its subsidiaries are subject to U.S. federal
income tax as well as income tax in various states and foreign
jurisdictions. While during 2009, the Company settled tax audits
in various jurisdictions, our uncertain tax positions are
related to tax years that may be subject to examination by the
relevant taxing authority. The Company’s earliest open tax
years in its key jurisdictions are as follows:
|
Jurisdiction
|
||||
|
United States
|
2004 | |||
|
Canada
|
2005 | |||
|
Egypt
|
1998 | |||
|
Australia
|
2001 | |||
|
United Kingdom
|
2003 | |||
|
Argentina
|
2003 | |||
| 7. | CAPITAL STOCK |
Common
Stock Outstanding
| 2009 | 2008 | 2007 | ||||||||||
|
Balance, beginning of year
|
334,710,064 | 332,927,143 | 330,737,425 | |||||||||
|
Shares issued for stock-based compensation plans:
|
||||||||||||
|
Treasury shares issued
|
404,232 | 350,895 | 651,022 | |||||||||
|
Common shares issued
|
1,322,676 | 1,432,026 | 1,538,696 | |||||||||
|
Balance, end of year
|
336,436,972 | 334,710,064 | 332,927,143 | |||||||||
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, 2009, 2008 and 2007 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.
| 2009 | 2008 | 2007 | ||||||||||||||||||||||||||||||||||
| Loss | Shares | Per Share | Income | Shares | Per Share | Income | Shares | Per Share | ||||||||||||||||||||||||||||
| (In thousands, except per share amounts) | ||||||||||||||||||||||||||||||||||||
|
Basic:
|
||||||||||||||||||||||||||||||||||||
|
Income (loss) attributable to common stock
|
$ | (291,692 | ) | 335,852 | $ | (.87 | ) | $ | 706,274 | 334,351 | $ | 2.11 | $ | 2,806,678 | 332,192 | $ | 8.45 | |||||||||||||||||||
|
Effect of Dilutive Securities:
|
||||||||||||||||||||||||||||||||||||
|
Stock options and others
|
$ | — | — | $ | — | $ | — | 2,840 | $ | (.02 | ) | $ | — | 2,404 | $ | (.06 | ) | |||||||||||||||||||
|
Diluted:
|
||||||||||||||||||||||||||||||||||||
|
Income (loss) attributable to common stock, including assumed
conversions
|
$ | (291,692 | ) | 335,852 | $ | (.87 | ) | $ | 706,274 | 337,191 | $ | 2.09 | $ | 2,806,678 | 334,596 | $ | 8.39 | |||||||||||||||||||
The diluted earnings per share calculation excludes options and
restricted shares that were anti-dilutive totaling
4.2 million, 673,801 and 482,994 for the years ended
December 31, 2009, 2008 and 2007, respectively.
F-26
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Common
Stock Dividend
The Company paid common stock dividends of $.60, $.70 and $.60
per share in 2009, 2008 and 2007, 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 Company’s 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 will be 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 2009, 2008 and 2007, stock-based compensation expensed was
$104 million, $52 million and $73 million
($67 million, $34 million and $47 million after
tax), respectively. Costs related to the plans are capitalized
or expensed based on the nature of each employee’s
activities. A description of the Company’s stock-based
compensation plans and related costs follows:
| 2009 | 2008 | 2007 | ||||||||||
| (In millions) | ||||||||||||
|
Stock-based compensation expensed:
|
||||||||||||
|
General and administrative
|
$ | 67 | $ | 34 | $ | 48 | ||||||
|
Lease operating expenses
|
37 | 18 | 25 | |||||||||
|
Stock-based compensation capitalized
|
46 | 21 | 37 | |||||||||
| $ | 150 | $ | 73 | $ | 110 | |||||||
Stock
Options
As of December 31, 2009, officers and employees held
options to purchase shares of the Company’s 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
Apache’s 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 Company’s stockholders.
On October 31, 1996, the Company also established the 1996
Performance Stock Option Plan (the Performance Plan) for
substantially all full-time employees, excluding officers and
certain other key employees. As of December 31, 2009, all
options granted under the Performance Plan had been exercised or
cancelled.
F-27
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
A summary of stock options issued under the Stock Option Plans,
the 2007 Plan and the Performance Plan in 2009 is presented in
the table and narrative below (shares in thousands):
| 2009 | ||||||||
|
Shares
|
Weighted Average
|
|||||||
| Under Option | Exercise Price | |||||||
|
Outstanding, beginning of year
|
5,976 | $ | 66.34 | |||||
|
Granted
|
1,184 | 82.57 | ||||||
|
Exercised
|
(957 | ) | 44.67 | |||||
|
Forfeited or expired
|
(283 | ) | 82.98 | |||||
|
Outstanding, end of year(1)
|
5,920 | 72.29 | ||||||
|
Expected to vest(1)
|
2,194 | 83.71 | ||||||
|
Exercisable, end of year(1)
|
3,254 | 62.57 | ||||||
|
Available for grant, end of year
|
4,541 | |||||||
|
Weighted average fair value of options granted during the year
|
$ | 29.71 | ||||||
| (1) | As of December 31, 2009, the weighted average remaining contractual life for options outstanding, expected to vest, and exercisable is 6.5 years, 8.1 years and 5.2 years, respectively. The aggregate intrinsic value of options outstanding, expected to vest and exercisable at year-end was $193 million, $49 million and $135 million, respectively. The weighted-average grant-date fair value of options granted during the years 2009, 2008 and 2007 was $29.71, $39.76 and $23.01, 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 Company’s 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.
| 2009 | 2008 | 2007 | ||||||||||
|
Expected volatility
|
38.73 | % | 27.93 | % | 24.60 | % | ||||||
|
Expected dividend yields
|
.73 | % | .53 | % | .79 | % | ||||||
|
Expected term (in years)
|
5.5 | 5.5 | 5.5 | |||||||||
|
Risk-free rate
|
2.06 | % | 3.04 | % | 4.51 | % | ||||||
The intrinsic value of options exercised during 2009, 2008 and
2007 was approximately $39 million, $100 million and
$105 million, respectively. The cash received from exercise
of options during 2009 was approximately $43 million. The
Company realized an additional tax benefit of approximately
$9 million for the amount of intrinsic value in excess of
compensation cost recognized in 2009. As of December 31,
2009, the total compensation cost related to non-vested options
not yet recognized was $56 million, which will be
recognized over the remaining vesting period of the options.
Stock
Appreciation Rights
In 2003 and 2004, the Company issued a total of 1,809,060 and
1,334,300, respectively, of stock appreciation rights (SARs) to
non-executive employees in lieu of stock options. The SARs vest
ratably over four years and will be 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
F-28
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
December 31, 2009 was 777,708. The Company records
compensation expense on the vested SARs outstanding based on the
fair value of the SARs at the end of each period because SARs
are cash-settled. As of year-end, the weighted-average fair
value of SARs outstanding was $69.54 based on the Black-Scholes
valuation methodology using assumptions comparable to those
discussed above. During 2009, 127,031 SARs were exercised. The
aggregate of cash payments made to settle SARs was
$5 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, that are for eligible employees including officers.
The programs created under the 2007 Plan have been approved by
Apache’s Board of Directors. In 2009, the Company awarded
1,119,936 restricted stock units at a per-share market price of
$84.30. In 2008 and 2007, the Company awarded 787,846 and
399,500 restricted stock units at a per-share market price of
$136.05 and $77.31, 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 2009, 2008 and 2007, $35.6 million
($22.9 million after tax), $20.1 million
($13.0 million after tax) and $8.2 million
($5.3 million after tax), respectively, was charged to
expense. In 2009, 2008 and 2007, $11.8 million,
$5.9 million and $1.0 million was capitalized,
respectively. As of December 31, 2009, there was
$150 million of total unrecognized compensation cost
related to 1,835,263 unvested restricted stock units. The
weighted-average remaining life of unvested restricted stock
units is approximately 1.8 years.
The total fair value of these awards vested during 2009, 2008
and 2007 was approximately $34 million, $15 million
and $7 million, respectively.
|
Weighted-Average
|
||||||||
|
Grant-Date
|
||||||||
|
Restricted Stock
|
Shares | Fair Value | ||||||
| (In thousands) | ||||||||
|
Non-vested at January 1, 2009
|
1,152 | $ | 115.72 | |||||
|
Granted
|
1,120 | 84.30 | ||||||
|
Vested
|
(318 | ) | 107.35 | |||||
|
Forfeited
|
(119 | ) | 101.42 | |||||
|
Non-vested at December 31, 2009
|
1,835 | $ | 98.95 | |||||
On May 7, 2008, the Stock Option Plan Committee of
Apache’s Board of Directors awarded its Chief Executive
Officer 250,000 restricted stock units, 50,000 of which vested
on July 1, 2009. The remaining 200,000 shares vest
ratably on the first business day of the years 2010, 2011, 2012
and 2013. Upon vesting, the Company will issue one share of the
Company’s common stock as settlement for each restricted
stock unit. Thirty thousand of the shares vesting each year will
not be eligible for sale by the executive until such time as he
retires or otherwise terminates employment with the Company.
This award was made under the terms of the Company’s 2007
Omnibus Equity Compensation Plan.
In August 2008, the Company established, pursuant to the
Company’s 2007 Omnibus Equity Compensation Plan, the
Non-Employee Directors’ Restricted Stock Units Program (the
RSU Program). Each non-employee director was awarded 1,500
restricted stock units on August 14, 2008 under the RSU
Program, with half of the restricted stock units vesting thirty
days after the grant and the other half vesting on the one-year
anniversary date of the grant. Each year, all non-employee
directors will be eligible to receive grants of restricted stock
units comparable in value to the 2008 grant. Non-employee
directors are required to choose, at the time of each award,
whether such award will vest as 100 percent common stock or
a combination of 40 percent cash and 60 percent common
stock.
On February 12, 2009, the Company awarded Roger B. Plank,
President, John A. Crum, Co-Chief Operating Officer and
President — North America, and Rodney J. Eichler,
Co-Chief Operating Officer and President —
F-29
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
International, each 62,500 restricted stock units pursuant to
Apache’s 2007 Omnibus Equity Compensation Plan. Twenty
percent of such restricted stock units will vest on each of
April 1, 2010, February 12, 2011, February 12,
2012, February 11, 2013 and February 11, 2014.
Additionally, on November 18, 2009, the Company awarded
five other key officers each 20,000 restricted stock units
pursuant to Apache’s 2007 Omnibus Equity Compensation Plan.
Twenty percent of these restricted stock units will vest on each
of December 31, 2010, November 18, 2011,
November 19, 2012, November 18, 2013 and
November 18, 2014. Upon vesting, Apache will issue one
share of Apache’s common stock as settlement for each
restricted stock unit. Sixty percent of the shares vesting each
year for each recipient will be subject to the restriction that
none of those shares will be eligible for sale by the recipient
until such time as he retires or otherwise terminates employment
with Apache.
Subsequent
Events
To provide long-term incentives for Apache employees to deliver
competitive returns to our stockholders, in January 2010 the
Company’s Board of Directors approved the 2010 Performance
Program, pursuant to the 2007 Omnibus Equity Compensation Plan.
Eligible employees received an initial conditional restricted
stock unit award of 541,440 units, with the ultimate number
of restricted stock units to be awarded, if any, 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 Company’s Board
of Directors also approved a one-time restricted stock unit
award of 502,470 shares to eligible Apache employees, with
one-third of the units granted immediately vesting and an
additional one-third vesting on each of the first and second
anniversaries of the grant date.
Share
Appreciation Plans
The Company has previously utilized share appreciation plans to
provide incentives for substantially all full-time employees and
officers to increase Apache’s share price within a stated
measurement period. To achieve the payout, the Company’s
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 would be 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 Company’s Board of Directors, pursuant to the Company’s 2007 Omnibus Equity Compensation Plan, approved the 2008 Share Appreciation Program with a target to increase Apache’s 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. As of December 31, 2009, neither share price threshold had been met. | |
| • | On May 5, 2005, the Company’s stockholders approved the 2005 Share Appreciation Plan, with a target to increase Apache’s 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. Apache’s 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 installment was awarded in June 2009, and the fourth and final installment will be awarded in June 2010. Apache’s share price exceeded the $108 threshold for the 10-day requirement as of February 29, 2008. |
F-30
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| The first and second installments were awarded in March 2008 and 2009, and the third and fourth installments will be awarded in March 2010 and 2011. |
A summary of the number of shares contingently issuable as of
December 31, 2009, 2008 and 2007 for each plan is presented
in the table below:
|
Shares Subject to
|
||||||||||||
| Conditional Grants | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
|
2008 Share Appreciation Program
|
||||||||||||
|
Outstanding, beginning of year
|
2,814 | — | — | |||||||||
|
Granted
|
93 | 2,929 | — | |||||||||
|
Issued
|
— | — | — | |||||||||
|
Forfeited or cancelled
|
(315 | ) | (115 | ) | — | |||||||
|
Outstanding, end of year(1)
|
2,592 | 2,814 | — | |||||||||
|
Weighted-average fair value of conditional grants(2)
|
$ | 79.61 | $ | 81.73 | $ | — | ||||||
|
2005 Share Appreciation Plan
|
||||||||||||
|
Outstanding, beginning of year
|
2,001 | 2,945 | 3,470 | |||||||||
|
Granted
|
— | — | 189 | |||||||||
|
Issued(5)
|
(815 | ) | (805 | ) | (331 | ) | ||||||
|
Forfeited or cancelled
|
(83 | ) | (139 | ) | (383 | ) | ||||||
|
Outstanding, end of year(3)
|
1,103 | 2,001 | 2,945 | |||||||||
|
Weighted-average fair value of conditional grants(4)
|
$ | 24.29 | $ | 24.98 | $ | 25.28 | ||||||
| (1) | Represents shares issuable upon vesting of $216 and $162 per share price goals of 1,556,160 and 1,035,640 shares, respectively, in 2009 and 1,685,430 and 1,128,320 shares, respectively, in 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 2.99 percent; (ii) expected volatility of 28.25 percent; and (iii) expected dividend yield of .54 percent. | |
| (3) | Represents shares issuable upon vesting of $81 and $108 per share price goals of 261,226 and 842,261 shares, respectively, in 2009, 581,008 and 1,420,177 shares, respectively, in 2008 and 928,297 and 2,016,629 shares, respectively, in 2007. | |
| (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. | |
| (5) | The total fair value of these awards vested during 2009, 2008 and 2007 was approximately $21 million, $21 million and $11 million, respectively. |
Current accounting practices dictate that, regardless of whether
these thresholds are ultimately achieved, the Company will
recognize, over time, the fair value cost determined at the
grant date based on numerous assumptions, including an estimate
of the likelihood that Apache’s stock price will achieve
these thresholds and the expected forfeiture rate. Over the
expected service life of each program, the Company will
recognize total expense and capitalized costs of approximately
$199 million through 2014 and $80 million through 2011
for the 2008 Share
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CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Appreciation Program and the 2005 Share Appreciation Plan,
respectively. 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, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In millions) | ||||||||||||
|
2008 Share Appreciation Program
|
||||||||||||
|
Compensation expense
|
$ | 23.2 | $ | 15.2 | $ | — | ||||||
|
Compensation expense, net of tax
|
14.9 | 9.8 | — | |||||||||
|
Capitalized costs
|
12.6 | 8.3 | — | |||||||||
|
2005 Share Appreciation Plan
|
||||||||||||
|
Compensation expense
|
$ | 6.4 | $ | 9.4 | $ | 10.6 | ||||||
|
Compensation expense, net of tax
|
4.1 | 6.0 | 6.8 | |||||||||
|
Capitalized costs
|
3.3 | 4.8 | 5.4 | |||||||||
Preferred
Stock
The Company has five million 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 Apache’s outstanding common stock
(flip in event); each Right will become exercisable for shares
of Apache’s 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
Apache’s 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 Company’s
outstanding shares of common stock is determined to be fair by
Apache’s 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.
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
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CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
of $98.4 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, 2008 and 2007, Apache accrued a total of
$5.7 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 $6.6 million in dividends on
this stock during 2009, compared to $5.7 million each year
for 2008 and 2007. The difference of $1.6 million between
the redemption amount and the initial net proceeds was
recognized as additional preferred stock dividends in
conjunction with the redemption of these shares on
December 30, 2009.
Accumulated
Other Comprehensive Income (Loss)
Components of accumulated other comprehensive income (loss)
consists of the following:
| For the Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
|
Currency translation adjustment(1)
|
$ | (108,750 | ) | $ | (108,750 | ) | $ | (108,750 | ) | |||
|
Unrealized gain (loss) on derivatives (Note 3)
|
(169,906 | ) | 137,827 | (411,678 | ) | |||||||
|
Unfunded pension and post retirement benefit plan
|
(11,846 | ) | (7,313 | ) | 217 | |||||||
|
Accumulated other comprehensive income (loss)
|
$ | (290,502 | ) | $ | 21,764 | $ | (520,211 | ) | ||||
| (1) | Prior to October 1, 2002, the Company’s 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 Company’s Canadian operations. |
| 8. | COMMITMENTS AND CONTINGENCIES |
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 $20 million for all legal contingencies that
are deemed to be probable of occurring and can be reasonably
estimated. Apache’s 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 management’s estimate, none of the
actions are believed by management to involve future amounts
that would be material to Apache’s financial position or
results of operations after consideration of recorded accruals.
It is management’s opinion that the loss for any other
litigation matters and claims that are reasonably possible to
occur will not have a material adverse affect on the
Company’s financial position or results of operations.
Legal
Matters
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
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CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 how or 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 PNRA’s 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 a million dollars. 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 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
have filed a petition with the Fifth Circuit for a rehearing
en banc
.
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 Lloyd’s London and other
insurers, against the Company and its subsidiaries in Texas
state court,
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CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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, 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
government’s 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 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 offences 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
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CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 NOPSA’s 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 Lloyd’s 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 Company’s
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 (DoCEP). The joint inquiry’s
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.
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 AUD$50,000. The Company
subsidiary does not believe that the charge has merit and plans
to vigorously pursue its defenses.
Seismic
License
In December 1996, the Company and Fairfield Industries
Incorporated entered into a Master Licensing Agreement for the
licensing of seismic data relating to certain blocks in the Gulf
of Mexico. The Company and Fairfield also entered into
supplemental agreements specifying the data to be licensed to
the Company as well as the consideration due Fairfield. In
February 2009, the Company filed an action in Texas state court
seeking a declaration of the parties’ contractual
obligations. The Company and its subsidiary, GOM Shelf LLC, have
also asserted a claim to recover damages for certain
overpayments to Fairfield under the parties’ agreements.
Fairfield and a related entity, Fairfield Royalty Corporation,
have attempted to counterclaim to recover unspecified damages
for alleged underpayments. Because the lawsuit is still in the
discovery phase, potential exposure related to the attempted
counterclaim is not currently determinable. While an adverse
judgment is possible with respect to the attempted counterclaim,
the Company does not believe that the attempted counterclaim has
merit and plans to vigorously pursue all defenses.
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 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
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CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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
Apache’s satisfaction, or agree to assume liability for the
remediation of the property. The Company’s 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 our estimation, neither these expenses nor
expenses related to training and compliance programs are likely
to have a material impact on our financial condition.
As of December 31, 2009, the Company had an undiscounted
reserve for environmental remediation of approximately
$27 million. Apache is not aware of any environmental
claims existing as of December 31, 2009 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 Company’s properties.
Also, the Government of Alberta Climate Change and Emissions
Management Act requires companies to meet emissions intensity
reduction obligations either by making operational improvements
to reduce emissions or by making compliance obligation payments.
Payments made in 2009 to comply with the requirements of this
act based on the volume of GHG emitted from Apache Canada
Ltd.’s Zama gas processing facility in 2008 totaled
approximately $300,000.
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 pension 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 employee’s annual covered compensation. In
addition, the Company annually contributes six percent of each
participating employee’s 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 employee’s salary and that accepts
employee contributions and the Company’s matching
contributions in excess of the government mandated limitations
imposed in the 401(k) savings plan and money purchase retirement
plan.
Vesting in the Company’s 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.
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.
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CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The aggregate annual cost of the 401(k) savings plans, the money
purchase retirement plan and the non-qualified
retirement/savings plans was $66 million, $52 million
and $59 million for 2009, 2008 and 2007, respectively.
Apache also provides a funded noncontributory defined benefit
pension plan (U.K. Pension Plan) covering certain employees of
the Company’s 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 Sea’s 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.
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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,
2009, 2008 and 2007, 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.
| 2009 | 2008 | 2007 | ||||||||||||||||||||||
|
Pension
|
Postretirement
|
Pension
|
Postretirement
|
Pension
|
Postretirement
|
|||||||||||||||||||
| Benefits | Benefits | Benefits | Benefits | Benefits | Benefits | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Change in Projected Benefit Obligation
|
||||||||||||||||||||||||
|
Projected benefit obligation beginning of year
|
$ | 99,132 | $ | 17,399 | $ | 129,883 | $ | 14,918 | $ | 125,627 | $ | 17,226 | ||||||||||||
|
Service cost
|
4,569 | 1,547 | 5,554 | 1,484 | 7,255 | 1,552 | ||||||||||||||||||
|
Interest cost
|
5,826 | 1,044 | 6,705 | 977 | 6,508 | 978 | ||||||||||||||||||
|
Foreign currency exchange rate changes
|
13,035 | — | (37,602 | ) | — | 2,131 | — | |||||||||||||||||
|
Amendments
|
— | — | — | — | — | — | ||||||||||||||||||
|
Actuarial losses (gains)
|
16,530 | (720 | ) | (1,619 | ) | 166 | (9,241 | ) | (4,770 | ) | ||||||||||||||
|
Effect of curtailment and settlements
|
— | — | — | — | — | — | ||||||||||||||||||
|
Benefits paid
|
(3,786 | ) | (1,023 | ) | (3,789 | ) | (284 | ) | (2,397 | ) | (180 | ) | ||||||||||||
|
Retiree contributions
|
— | 176 | — | 138 | — | 112 | ||||||||||||||||||
|
Projected benefit obligation at end of year
|
135,306 | 18,423 | 99,132 | 17,399 | 129,883 | 14,918 | ||||||||||||||||||
|
Change in Plan Assets
|
||||||||||||||||||||||||
|
Fair value of plan assets at beginning of year
|
82,609 | — | 122,233 | — | 112,821 | — | ||||||||||||||||||
|
Actual return on plan assets
|
12,264 | — | (13,337 | ) | — | 4,704 | — | |||||||||||||||||
|
Foreign currency exchange rates
|
11,049 | — | (32,309 | ) | — | 1,881 | — | |||||||||||||||||
|
Employer contributions
|
16,017 | 847 | 9,811 | 146 | 5,224 | 68 | ||||||||||||||||||
|
Benefits paid
|
(3,786 | ) | (1,023 | ) | (3,789 | ) | (284 | ) | (2,397 | ) | (180 | ) | ||||||||||||
|
Retiree contributions
|
— | 176 | — | 138 | — | 112 | ||||||||||||||||||
|
Fair value of plan assets at end of year
|
118,153 | — | 82,609 | — | 122,233 | — | ||||||||||||||||||
|
Funded status at end of year
|
$ | (17,153 | ) | $ | (18,423 | ) | $ | (16,523 | ) | $ | (17,399 | ) | $ | (7,650 | ) | $ | (14,918 | ) | ||||||
|
Amounts recognized in Consolidated Balance Sheet
|
||||||||||||||||||||||||
|
Current liability
|
— | (560 | ) | — | (565 | ) | — | (363 | ) | |||||||||||||||
|
Non current liability
|
(17,153 | ) | (17,863 | ) | (16,523 | ) | (16,834 | ) | (7,650 | ) | (14,555 | ) | ||||||||||||
| $ | (17,153 | ) | $ | (18,423 | ) | $ | (16,523 | ) | $ | (17,399 | ) | $ | (7,650 | ) | $ | (14,918 | ) | |||||||
|
Pretax Amounts Recognized in Accumulated
|
||||||||||||||||||||||||
|
Other Comprehensive Income
|
||||||||||||||||||||||||
|
Accumulated gain (loss)
|
(23,905 | ) | 473 | (13,854 | ) | (246 | ) | 1,049 | (80 | ) | ||||||||||||||
|
Prior service cost
|
— | — | — | — | — | — | ||||||||||||||||||
|
Transition asset (obligation)
|
— | (308 | ) | — | (353 | ) | — | (397 | ) | |||||||||||||||
| $ | (23,905 | ) | $ | 165 | $ | (13,854 | ) | $ | (599 | ) | $ | 1,049 | $ | (477 | ) | |||||||||
|
Weighted Average Assumptions used as of December 31
|
||||||||||||||||||||||||
|
Discount rate
|
5.70 | % | 5.56 | % | 5.50 | % | 6.03 | % | 5.60 | % | 6.01 | % | ||||||||||||
|
Salary increases
|
5.30 | % | 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
|
N/A | 7.50 | % | N/A | 8.00 | % | N/A | 8.00 | % | |||||||||||||||
|
Ultimate in 2015
|
N/A | 5.00 | % | N/A | 5.00 | % | N/A | 5.00 | % | |||||||||||||||
F-39
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
As of December 31, 2009, 2008 and 2007, the accumulated
benefit obligation for the pension plan was $89 million,
$69 million and $91 million, respectively.
Apache’s 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 Company’s plan assets are
summarized below:
|
Percentage of
|
||||||||||||
|
Plan Assets at
|
||||||||||||
|
Target Allocation
|
Year-End | |||||||||||
| 2009 | 2009 | 2008(1) | ||||||||||
|
Asset Category
|
||||||||||||
|
Equity securities:
|
||||||||||||
|
U.K. quoted equities
|
30 | % | 28 | % | N/A | |||||||
|
Overseas quoted equities
|
20 | % | 19 | % | N/A | |||||||
|
Total equity securities
|
50 | % | 47 | % | 45 | % | ||||||
|
Debt securities:
|
||||||||||||
|
U.K. Government bonds
|
30 | % | 31 | % | N/A | |||||||
|
U.K. corporate bonds
|
20 | % | 18 | % | N/A | |||||||
|
Debt securities
|
50 | % | 49 | % | 51 | % | ||||||
|
Cash
|
— | 4 | % | 4 | % | |||||||
|
Total
|
100 | % | 100 | % | 100 | % | ||||||
| (1) | FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” as codified into ASC Topic 715, “Compensation — Retirement Benefits,” requires additional disclosures about the fair value of major categories of plan assets. This standard was effective as of December 31, 2009, and the expanded disclosures are not required for periods presented for comparative purposes. |
The plan’s 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 10 — Fair Value
F-40
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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, 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 thousands) | ||||||||||||||||
|
Equity securities:
|
||||||||||||||||
|
U.K. quoted equities(1)
|
$ | 33,764 | $ | — | $ | — | $ | 33,764 | ||||||||
|
Overseas quoted equities(2)
|
22,163 | — | — | 22,163 | ||||||||||||
|
Total equity securities
|
55,927 | — | — | 55,927 | ||||||||||||
|
Debt securities:
|
||||||||||||||||
|
U.K. Government bonds(3)
|
36,048 | — | — | 36,048 | ||||||||||||
|
U.K. corporate bonds(4)
|
21,160 | — | — | 21,160 | ||||||||||||
|
Total debt securities
|
57,208 | — | — | 57,208 | ||||||||||||
|
Cash
|
5,018 | — | — | 5,018 | ||||||||||||
|
Fair value of plan assets
|
$ | 118,153 | $ | — | $ | — | $ | 118,153 | ||||||||
| (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-41
Table of Contents
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, 2009, 2008 and 2007:
| 2009 | 2008 | 2007 | ||||||||||||||||||||||
|
Pension
|
Postretirement
|
Pension
|
Postretirement
|
Pension
|
Postretirement
|
|||||||||||||||||||
| Benefits | Benefits | Benefits | Benefits | Benefits | Benefits | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Components of Net Periodic Benefit Costs
|
||||||||||||||||||||||||
|
Service cost
|
$ | 4,569 | $ | 1,547 | $ | 5,554 | $ | 1,484 | $ | 7,255 | $ | 1,552 | ||||||||||||
|
Interest cost
|
5,826 | 1,044 | 6,705 | 977 | 6,508 | 978 | ||||||||||||||||||
|
Expected return on assets
|
(5,904 | ) | — | (7,479 | ) | — | (7,632 | ) | — | |||||||||||||||
|
Amortization of:
|
||||||||||||||||||||||||
|
Transition obligation
|
— | 44 | — | 44 | — | 44 | ||||||||||||||||||
|
Actuarial (gain) loss
|
— | — | — | — | — | 139 | ||||||||||||||||||
|
Net periodic benefit cost
|
$ | 4,491 | $ | 2,635 | $ | 4,780 | $ | 2,505 | $ | 6,131 | $ | 2,713 | ||||||||||||
|
Weighted Average Assumptions used to determine Net Periodic
Benefit Costs for the Years ended December 31
|
||||||||||||||||||||||||
|
Discount rate
|
5.50 | % | 6.03 | % | 5.60 | % | 6.01 | % | 5.10 | % | 5.77 | % | ||||||||||||
|
Salary increases
|
4.50 | % | N/A | 4.40 | % | N/A | 4.10 | % | N/A | |||||||||||||||
|
Expected return on assets
|
6.05 | % | N/A | 6.50 | % | N/A | 6.50 | % | N/A | |||||||||||||||
|
Healthcare cost trend
|
||||||||||||||||||||||||
|
— Initial
|
— | 8.00 | % | — | 8.00 | % | N/A | 9.00 | % | |||||||||||||||
|
— Ultimate in 2014
|
— | 5.00 | % | — | 5.00 | % | N/A | 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 thousands) | ||||||||
|
Effect on service and interest cost components
|
$ | 328 | $ | (282 | ) | |||
|
Effect on postretirement benefit obligation
|
2,015 | (1,767 | ) | |||||
Apache expects to contribute approximately $6 million to
its pension plan and $560,000 to its postretirement benefit plan
in 2010. The following benefit payments, which reflect expected
future service, as appropriate, are expected to be paid:
|
Pension
|
Postretirement
|
|||||||
| Benefits | Benefits | |||||||
| (In thousands) | ||||||||
|
2010
|
2,421 | 560 | ||||||
|
2011
|
4,225 | 716 | ||||||
|
2012
|
5,134 | 939 | ||||||
|
2013
|
3,583 | 1,212 | ||||||
|
2014
|
4,832 | 1,472 | ||||||
|
Years 2015 — 2019
|
27,397 | 11,444 | ||||||
F-42
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Contractual
Obligations
At December 31, 2009, 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 | 2010 | 2011-2013 | 2014-2015 | 2016 & Beyond | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Drilling rig commitments
|
$ | 480,511 | $ | 418,947 | $ | 61,564 | $ | — | $ | — | ||||||||||
|
Purchase obligations
|
610,700 | 381,976 | 228,724 | — | — | |||||||||||||||
|
E&D commitments
|
446,134 | 125,320 | 254,146 | 66,668 | — | |||||||||||||||
|
Firm transportation agreements
|
313,954 | 50,179 | 131,093 | 79,608 | 53,074 | |||||||||||||||
|
Office and related equipment
|
123,711 | 25,640 | 61,423 | 13,119 | 23,529 | |||||||||||||||
|
Oil and gas operations equipment
|
468,496 | 82,165 | 123,272 | 52,060 | 210,999 | |||||||||||||||
|
Other
|
5,100 | 5,100 | — | — | — | |||||||||||||||
|
Total Net Minimum Commitments
|
$ | 2,448,606 | $ | 1,089,327 | $ | 860,222 | $ | 211,455 | $ | 287,602 | ||||||||||
| • | Drilling rig commitments include day-rate and other contracts for use of drilling, completion and workover rigs. | |
| • | Purchase obligations include contractual obligations to buy or build oil and gas plants and facilities. | |
| • | E&D commitments generally consist 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. | |
| • | Firm transportation agreements relate to contractual obligations for capacity rights on third-party pipelines. | |
| • | Office and related equipment leases include office and other building rentals and related equipment leases. | |
| • | Oil and gas operations equipment includes floating production storage and offloading (FPSOs), compressors, helicopters and boats. |
Included in the table above are leases for buildings, facilities
and related equipment with varying expiration dates through
2035. Net rental expense was $38 million, $38 million
and $31 million for 2009, 2008 and 2007, respectively.
| 9. | SUBSEQUENT EVENTS |
Subsequent events have been evaluated for recognition and
disclosure through the date these financial statements were
filed with the SEC.
Kitimat
LNG Terminal
On January 13, 2010, Apache announced that its Apache
Canada Ltd. subsidiary has agreed to acquire 51 percent of
Kitimat LNG Inc.’s proposed LNG export terminal in British
Columbia. Apache also reserved 51 percent of gas throughput
capacity in the terminal.
The proposed Kitimat project, located at Bish Cove near the Port
of Kitimat about 405 miles north of Vancouver, has planned
capacity of about
700 MMcf/d,
or five million metric tons of LNG per year. Preliminary gross
construction cost estimates of C$3 billion will be refined
at the conclusion of Front-End Engineering and Design. The
project is projected to employ an estimated 1,500 people
during construction and 100 on a permanent basis.
F-43
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Kitimat is designed to be linked to the pipeline system
servicing Western Canada’s natural gas producing regions
via the proposed Pacific Trail Pipelines, a C$1.1 billion
project. In association with our acquisition of interest in the
Kitimat project, we also acquired a 25.5-percent interest in the
proposed pipeline and 350 MMcf/d of capacity rights.
| 10. | 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, and these
valuations have the lowest priority.
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 Apache’s 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 due to the
short-term nature or maturity of the instruments.
Commodity
Derivative Instruments
Apache’s commodity derivative instruments consist of
variable-to-fixed
price commodity swaps and options. The Company estimates the
fair values of derivative instruments using published commodity
futures price strips for the underlying commodities as of the
date of the estimate. The fair values of the Company’s
derivative instruments are not actively quoted in the open
market and are valued using forward commodity price curves
provided by a reputable third-party. These valuations are
Level 2 inputs. See Note 3 — Derivative
Instruments and Hedging Activities for further information.
The following table presents the Company’s 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, 2009
|
||||||||||||||||||||||||
|
Assets:
|
||||||||||||||||||||||||
|
Commodity Derivative Instruments
|
$ | — | $ | 75 | $ | — | $ | 75 | $ | (11 | ) | $ | 64 | |||||||||||
|
Liabilities:
|
||||||||||||||||||||||||
|
Commodity Derivative Instruments
|
— | 341 | — | 341 | (11 | ) | 330 | |||||||||||||||||
|
December 31, 2008
|
||||||||||||||||||||||||
|
Assets:
|
||||||||||||||||||||||||
|
Commodity Derivative Instruments
|
$ | — | $ | 225 | $ | — | $ | 225 | $ | (6 | ) | $ | 219 | |||||||||||
|
Liabilities:
|
||||||||||||||||||||||||
|
Commodity Derivative Instruments
|
— | 13 | — | 13 | (6 | ) | 7 | |||||||||||||||||
| (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. See Note 3 — Derivative Instruments and Hedging Activities for a discussion of net amounts recorded on the Consolidated Balance Sheet at December 31, 2009 and 2008. |
F-44
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 Apache’s Consolidated Balance Sheet.
The following methods and assumptions were used to estimate fair
values:
Asset
Retirement Obligations Incurred in Current Period
Apache estimates 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.
Note 4 — Asset Retirement Obligation provides a
summary of changes in the ARO liability.
Debt
The Company’s debt is recorded at the carrying amount on
its Consolidated Balance Sheet. The fair value of Apache’s
fixed-rate debt is based upon estimates provided by an
independent investment banking firm, which is a Level 2
fair value measurement. The carrying amount of floating-rate
debt approximates fair value because the
F-45
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
interest rates are variable and reflective of market rates. The
following table presents the carrying amounts and estimated fair
values of the Company’s debt at December 31, 2009 and
2008:
| December 31, 2009 | December 31, 2008 | |||||||||||||||
|
Carrying
|
Fair
|
Carrying
|
Fair
|
|||||||||||||
| Amount | Value | Amount | Value | |||||||||||||
| (In millions) | ||||||||||||||||
|
Long-term debt:
|
||||||||||||||||
|
Apache
|
||||||||||||||||
|
Money market lines of credit
|
$ | — | $ | — | $ | — | $ | — | ||||||||
|
Unsecured committed bank credit facilities
|
— | — | — | — | ||||||||||||
|
Commercial paper
|
— | — | — | — | ||||||||||||
|
6.25% debentures due 2012
|
399 | 439 | 399 | 417 | ||||||||||||
|
5.25% notes due 2013
|
499 | 538 | 499 | 502 | ||||||||||||
|
6.0% notes due 2013
|
398 | 440 | 398 | 413 | ||||||||||||
|
5.625% notes due 2017
|
500 | 535 | 500 | 496 | ||||||||||||
|
6.9% notes due 2018
|
399 | 467 | 398 | 433 | ||||||||||||
|
7.0% notes due 2018
|
149 | 175 | 149 | 162 | ||||||||||||
|
7.625% notes due 2019
|
149 | 181 | 149 | 170 | ||||||||||||
|
7.7% notes due 2026
|
100 | 122 | 100 | 114 | ||||||||||||
|
7.95% notes due 2026
|
179 | 224 | 179 | 209 | ||||||||||||
|
6.0% notes due 2037
|
993 | 1,064 | 993 | 963 | ||||||||||||
|
7.375% debentures due 2047
|
148 | 180 | 148 | 167 | ||||||||||||
|
7.625% debentures due 2096
|
149 | 172 | 149 | 167 | ||||||||||||
|
Subsidiary and other obligations
|
||||||||||||||||
|
Argentina overdraft lines of credit
|
7 | 7 | 13 | 13 | ||||||||||||
|
Apache PVG secured facility
|
350 | 350 | 100 | 100 | ||||||||||||
|
Notes due in 2016 and 2017
|
1 | 1 | 1 | 1 | ||||||||||||
|
Apache Finance Australia 7.0% notes due 2009
|
— | — | 100 | 100 | ||||||||||||
|
Apache Finance Canada 4.375% notes due 2015
|
350 | 365 | 350 | 325 | ||||||||||||
|
Apache Finance Canada 7.75% notes due 2029
|
297 | 375 | 297 | 340 | ||||||||||||
The carrying amount of the commercial paper and money market
lines of credit approximated fair value because the interest
rates are variable and reflective of market rates. The
Company’s trade receivables, trade payables and short-term
investments are, by their very nature, short-term. The carrying
values included in the accompanying Consolidated Balance Sheet
approximate fair value at December 31, 2009 and 2008.
| 11. | MAJOR CUSTOMERS |
In 2009, 2008 and 2007, purchases by Shell accounted for
18 percent, 17 percent and 12 percent,
respectively, of the Company’s worldwide oil and gas
production revenues.
Concentration
of Credit Risk
While Apache experienced a decline in the timeliness of receipts
from EGPC for oil and gas sales in recent years, the Company saw
significant improvement in collections throughout 2009.
F-46
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 12. | 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, 2009, the Company has production
in six countries: the United States (Gulf Coast and Central
Regions), Canada, Egypt, Australia, offshore the U.K. in the
North Sea and Argentina. Apache also has exploration interests
on the Chilean side of the island of Tierra del Fuego. Financial
information by country is presented below:
|
Other
|
||||||||||||||||||||||||||||||||
| United States | Canada | Egypt | Australia | North Sea | Argentina | International | Total | |||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||||||
|
Oil and gas production revenues
|
$ | 3,049,699 | $ | 877,224 | $ | 2,553,037 | $ | 363,427 | $ | 1,368,797 | $ | 361,743 | $ | — | $ | 8,573,927 | ||||||||||||||||
|
Operating Expenses:
|
||||||||||||||||||||||||||||||||
|
Depreciation, depletion and amortization
|
||||||||||||||||||||||||||||||||
|
Recurring
|
946,922 | 256,758 | 578,501 | 203,722 | 260,020 | 149,140 | — | 2,395,063 | ||||||||||||||||||||||||
|
Additional
|
1,222,394 | 1,595,767 | — | — | — | — | — | 2,818,161 | ||||||||||||||||||||||||
|
Asset retirement obligation accretion
|
63,055 | 18,761 | — | 5,859 | 14,449 | 2,691 | — | 104,815 | ||||||||||||||||||||||||
|
Lease operating expenses
|
762,227 | 269,562 | 264,229 | 100,856 | 157,493 | 107,773 | — | 1,662,140 | ||||||||||||||||||||||||
|
Gathering and transportation
|
35,011 | 53,112 | 23,471 | — | 26,232 | 4,873 | — | 142,699 | ||||||||||||||||||||||||
|
Taxes other than income
|
120,903 | 43,152 | 8,406 | 9,976 | 382,828 | 14,171 | — | 579,436 | ||||||||||||||||||||||||
|
Operating Income (Loss)(1)
|
$ | (100,813 | ) | $ | (1,359,888 | ) | $ | 1,678,430 | $ | 43,014 | $ | 527,775 | $ | 83,095 | $ | — | 871,613 | |||||||||||||||
|
Other Income (Expense):
|
||||||||||||||||||||||||||||||||
|
Other
|
40,899 | |||||||||||||||||||||||||||||||
|
General and administrative
|
(343,883 | ) | ||||||||||||||||||||||||||||||
|
Financing costs, net
|
(242,238 | ) | ||||||||||||||||||||||||||||||
|
Income Before Income Taxes
|
$ | 326,391 | ||||||||||||||||||||||||||||||
|
Net Property and Equipment
|
$ | 9,859,048 | $ | 3,250,796 | $ | 3,910,149 | $ | 2,964,542 | $ | 1,655,428 | $ | 1,222,438 | $ | 38,214 | $ | 22,900,615 | ||||||||||||||||
|
Total Assets
|
$ | 11,526,300 | $ | 3,775,412 | $ | 5,625,707 | $ | 3,346,094 | $ | 2,443,839 | $ | 1,428,845 | $ | 39,546 | $ | 28,185,743 | ||||||||||||||||
|
Additions to Net Property and Equipment
|
$ | 1,341,884 | $ | 603,393 | $ | 873,271 | $ | 773,760 | $ | 379,247 | $ | 171,284 | $ | 10,757 | $ | 4,153,596 | ||||||||||||||||
|
2008
|
||||||||||||||||||||||||||||||||
|
Oil and gas production revenues
|
$ | 5,083,397 | $ | 1,650,402 | $ | 2,739,246 | $ | 371,669 | $ | 2,103,283 | $ | 379,842 | $ | — | $ | 12,327,839 | ||||||||||||||||
|
Operating Expenses:
|
||||||||||||||||||||||||||||||||
|
Depreciation, depletion and amortization
|
||||||||||||||||||||||||||||||||
|
Recurring
|
1,112,989 | 416,880 | 397,573 | 134,926 | 262,787 | 191,282 | — | 2,516,437 | ||||||||||||||||||||||||
|
Additional
|
2,667,440 | 1,689,392 | — | — | 568,450 | 408,539 | — | 5,333,821 | ||||||||||||||||||||||||
|
Asset retirement obligation accretion
|
66,189 | 14,173 | — | 5,921 | 13,215 | 1,850 | — | 101,348 | ||||||||||||||||||||||||
|
Lease operating expenses
|
925,977 | 336,871 | 241,455 | 103,627 | 190,966 | 110,729 | — | 1,909,625 | ||||||||||||||||||||||||
|
Gathering and transportation
|
39,739 | 62,848 | 20,896 | — | 28,382 | 4,626 | — | 156,491 | ||||||||||||||||||||||||
|
Taxes other than income
|
211,251 | 42,662 | 8,306 | 10,719 | 695,443 | 16,426 | — | 984,807 | ||||||||||||||||||||||||
|
Operating Income (Loss)(1)
|
$ | 59,812 | $ | (912,424 | ) | $ | 2,071,016 | $ | 116,476 | $ | 344,040 | $ | (353,610 | ) | $ | — | 1,325,310 | |||||||||||||||
|
Other Income (Expense):
|
||||||||||||||||||||||||||||||||
|
Other
|
61,911 | |||||||||||||||||||||||||||||||
|
General and administrative
|
(288,794 | ) | ||||||||||||||||||||||||||||||
|
Financing costs, net
|
(166,035 | ) | ||||||||||||||||||||||||||||||
|
Income Before Income Taxes
|
$ | 932,392 | ||||||||||||||||||||||||||||||
|
Net Property and Equipment
|
$ | 10,685,505 | $ | 4,500,040 | $ | 3,615,126 | $ | 2,393,894 | $ | 1,536,202 | $ | 1,200,294 | $ | 27,456 | $ | 23,958,517 | ||||||||||||||||
|
Total Assets
|
$ | 11,975,654 | $ | 5,846,269 | $ | 4,967,603 | $ | 2,626,588 | $ | 2,287,225 | $ | 1,445,864 | $ | 37,282 | $ | 29,186,485 | ||||||||||||||||
|
Additions to Net Property and Equipment
|
$ | 2,748,241 | $ | 871,521 | $ | 1,452,089 | $ | 937,875 | $ | 478,987 | $ | 363,018 | $ | 27,457 | $ | 6,879,188 | ||||||||||||||||
F-47
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
|
Other
|
||||||||||||||||||||||||||||||||
| United States | Canada | Egypt | Australia | North Sea | Argentina | International | Total | |||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
|
2007
|
||||||||||||||||||||||||||||||||
|
Oil and gas production revenues
|
$ | 4,306,108 | $ | 1,392,856 | $ | 2,011,796 | $ | 535,699 | $ | 1,399,201 | $ | 316,322 | $ | — | $ | 9,961,982 | ||||||||||||||||
|
Operating Expenses:
|
||||||||||||||||||||||||||||||||
|
Depreciation, depletion and amortization
|
1,074,669 | 413,074 | 306,084 | 190,606 | 196,888 | 166,470 | — | 2,347,791 | ||||||||||||||||||||||||
|
Asset retirement obligation accretion
|
70,006 | 9,144 | — | 3,684 | 12,511 | 1,093 | — | 96,438 | ||||||||||||||||||||||||
|
Lease operating expenses
|
802,164 | 331,403 | 174,859 | 81,288 | 182,388 | 80,753 | — | 1,652,855 | ||||||||||||||||||||||||
|
Gathering and transportation
|
38,086 | 54,412 | 15,242 | — | 26,647 | 3,020 | — | 137,407 | ||||||||||||||||||||||||
|
Taxes other than income
|
166,798 | 42,598 | 7,887 | 22,497 | 346,500 | 11,367 | — | 597,647 | ||||||||||||||||||||||||
|
Operating Income (Loss)(1)
|
$ | 2,154,385 | $ | 542,225 | $ | 1,507,724 | $ | 237,624 | $ | 634,267 | $ | 53,619 | $ | — | 5,129,844 | |||||||||||||||||
|
Other Income (Expense):
|
||||||||||||||||||||||||||||||||
|
Other
|
37,770 | |||||||||||||||||||||||||||||||
|
General and administrative
|
(275,065 | ) | ||||||||||||||||||||||||||||||
|
Financing costs, net
|
(219,937 | ) | ||||||||||||||||||||||||||||||
|
Income Before Income Taxes
|
$ | 4,672,612 | ||||||||||||||||||||||||||||||
|
Net Property and Equipment
|
$ | 11,919,013 | $ | 5,834,792 | $ | 2,560,609 | $ | 1,590,431 | $ | 1,889,651 | $ | 1,437,097 | $ | — | $ | 25,231,593 | ||||||||||||||||
|
Total Assets
|
$ | 12,195,552 | $ | 7,289,118 | $ | 3,360,494 | $ | 1,884,443 | $ | 2,229,502 | $ | 1,664,462 | $ | 11,080 | $ | 28,634,651 | ||||||||||||||||
|
Additions to Net Property and Equipment
|
$ | 2,912,541 | $ | 836,547 | $ | 1,059,793 | $ | 603,174 | $ | 541,761 | $ | 344,818 | $ | — | $ | 6,298,634 | ||||||||||||||||
| (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-48
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 13. | SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) |
Oil
and Gas Operations
The following table sets forth revenue and direct cost
information relating to the Company’s 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 thousands) | ||||||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||||||
|
Oil and gas production revenues
|
$ | 3,049,699 | $ | 877,224 | $ | 2,553,037 | $ | 363,427 | $ | 1,368,797 | $ | 361,743 | $ | — | $ | 8,573,927 | ||||||||||||||||
|
Operating cost:
|
||||||||||||||||||||||||||||||||
|
Depreciation, depletion and amortization
|
||||||||||||||||||||||||||||||||
|
Recurring(1)
|
914,795 | 250,253 | 578,246 | 201,580 | 255,539 | 147,352 | — | 2,347,765 | ||||||||||||||||||||||||
|
Additional
|
1,222,394 | 1,595,767 | — | — | — | — | — | 2,818,161 | ||||||||||||||||||||||||
|
Asset retirement obligation accretion
|
63,055 | 18,761 | — | 5,859 | 14,449 | 2,691 | — | 104,815 | ||||||||||||||||||||||||
|
Lease operating expenses
|
762,227 | 269,562 | 264,229 | 100,856 | 157,493 | 107,773 | — | 1,662,140 | ||||||||||||||||||||||||
|
Gathering and transportation
|
35,011 | 53,112 | 23,471 | — | 26,232 | 4,873 | — | 142,699 | ||||||||||||||||||||||||
|
Production taxes(2)
|
106,792 | 35,589 | — | 9,976 | 382,828 | 7,420 | — | 542,605 | ||||||||||||||||||||||||
|
Income tax
|
(19,374 | ) | (335,513 | ) | 809,804 | 13,547 | 266,128 | 32,072 | — | 766,664 | ||||||||||||||||||||||
| 3,084,900 | 1,887,531 | 1,675,750 | 331,818 | 1,102,669 | 302,181 | — | 8,384,849 | |||||||||||||||||||||||||
|
Results of operations
|
$ | (35,201 | ) | $ | (1,010,307 | ) | $ | 877,287 | $ | 31,609 | $ | 266,128 | $ | 59,562 | $ | — | $ | 189,078 | ||||||||||||||
|
Amortization rate per boe
|
$ | 12.10 | $ | 7.58 | $ | 8.86 | $ | 12.61 | $ | 11.40 | $ | 8.62 | $ | — | $ | 10.34 | ||||||||||||||||
|
2008
|
||||||||||||||||||||||||||||||||
|
Oil and gas production revenues
|
$ | 5,083,397 | $ | 1,650,402 | $ | 2,739,246 | $ | 371,669 | $ | 2,103,283 | $ | 379,842 | $ | — | $ | 12,327,839 | ||||||||||||||||
|
Operating cost:
|
||||||||||||||||||||||||||||||||
|
Depreciation, depletion and amortization
|
||||||||||||||||||||||||||||||||
|
Recurring(1)
|
1,081,027 | 410,047 | 397,573 | 133,126 | 260,831 | 187,918 | — | 2,470,522 | ||||||||||||||||||||||||
|
Additional
|
2,667,440 | 1,689,392 | — | — | 568,450 | 408,539 | — | 5,333,821 | ||||||||||||||||||||||||
|
Asset retirement obligation accretion
|
66,189 | 14,173 | — | 5,921 | 13,215 | 1,850 | — | 101,348 | ||||||||||||||||||||||||
|
Lease operating expenses
|
925,977 | 336,871 | 241,455 | 103,627 | 190,966 | 110,729 | — | 1,909,625 | ||||||||||||||||||||||||
|
Gathering and transportation
|
39,739 | 62,848 | 20,896 | — | 28,382 | 4,626 | — | 156,491 | ||||||||||||||||||||||||
|
Production taxes(2)
|
201,590 | 33,643 | — | 10,719 | 695,443 | — | — | 941,395 | ||||||||||||||||||||||||
|
Income tax
|
36,009 | (215,536 | ) | 998,075 | 35,483 | 172,998 | (116,837 | ) | — | 910,192 | ||||||||||||||||||||||
| 5,017,971 | 2,331,438 | 1,657,999 | 288,876 | 1,930,285 | 596,825 | — | 11,823,394 | |||||||||||||||||||||||||
|
Results of operations
|
$ | 65,426 | $ | (681,036 | ) | $ | 1,081,247 | $ | 82,793 | $ | 172,998 | $ | (216,983 | ) | $ | — | $ | 504,445 | ||||||||||||||
|
Amortization rate per boe
|
$ | 14.08 | $ | 13.11 | $ | 8.48 | $ | 11.26 | $ | 11.89 | $ | 10.49 | $ | — | $ | 12.06 | ||||||||||||||||
|
2007
|
||||||||||||||||||||||||||||||||
|
Oil and gas production revenues
|
$ | 4,306,108 | $ | 1,392,856 | $ | 2,011,796 | $ | 535,699 | $ | 1,399,201 | $ | 316,322 | $ | — | $ | 9,961,982 | ||||||||||||||||
|
Operating cost:
|
||||||||||||||||||||||||||||||||
|
Depreciation, depletion and amortization(1)
|
1,048,213 | 400,630 | 306,084 | 189,208 | 196,054 | 163,557 | — | 2,303,746 | ||||||||||||||||||||||||
|
Asset retirement obligation accretion
|
70,006 | 9,144 | — | 3,684 | 12,511 | 1,093 | — | 96,438 | ||||||||||||||||||||||||
|
Lease operating expenses
|
802,164 | 331,403 | 174,859 | 81,288 | 182,388 | 80,753 | — | 1,652,855 | ||||||||||||||||||||||||
|
Gathering and transportation
|
38,086 | 54,412 | 15,242 | — | 26,647 | 3,020 | — | 137,407 | ||||||||||||||||||||||||
|
Production taxes(2)
|
152,274 | 34,724 | — | 22,497 | 346,500 | — | — | 555,995 | ||||||||||||||||||||||||
|
Income tax
|
779,355 | 168,763 | 727,493 | 81,267 | 317,551 | 23,765 | — | 2,098,194 | ||||||||||||||||||||||||
| 2,890,098 | 999,076 | 1,223,678 | 377,944 | 1,081,651 | 272,188 | — | 6,844,635 | |||||||||||||||||||||||||
|
Results of Operations
|
$ | 1,416,010 | $ | 393,780 | $ | 788,118 | $ | 157,755 | $ | 317,550 | $ | 44,134 | $ | — | $ | 3,117,347 | ||||||||||||||||
|
Amortization rate per boe
|
$ | 12.62 | $ | 11.81 | $ | 7.15 | $ | 10.36 | $ | 9.96 | $ | 9.17 | $ | — | $ | 10.78 | ||||||||||||||||
| (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 12 — Business Segment Information. |
F-49
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (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 12 — Business Segment Information. |
Costs
Incurred in Oil and Gas Property Acquisitions, Exploration, and
Development Activities
|
Other
|
||||||||||||||||||||||||||||||||
| United States | Canada | Egypt | Australia | North Sea | Argentina | International | Total | |||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||||||
|
Acquisitions:
|
||||||||||||||||||||||||||||||||
|
Proved
|
$ | 195,966 | $ | 13,182 | $ | — | $ | — | $ | — | $ | 24,189 | $ | — | $ | 233,337 | ||||||||||||||||
|
Unproved
|
— | — | 39,000 | 37,835 | — | 300 | — | 77,135 | ||||||||||||||||||||||||
|
Exploration
|
232,980 | 178,564 | 438,294 | 182,467 | 105,137 | 96,783 | 10,757 | 1,244,982 | ||||||||||||||||||||||||
|
Development
|
891,825 | 325,772 | 244,842 | 473,816 | 270,348 | 46,628 | — | 2,253,231 | ||||||||||||||||||||||||
|
Costs incurred(1)
|
$ | 1,320,771 | $ | 517,518 | $ | 722,136 | $ | 694,118 | $ | 375,485 | $ | 167,900 | $ | 10,757 | $ | 3,808,685 | ||||||||||||||||
|
(1) Includes capitalized interest and asset retirement costs as
follows:
|
||||||||||||||||||||||||||||||||
|
Capitalized interest
|
$ | 14,666 | $ | 11,936 | $ | 7,388 | $ | 15,423 | $ | 281 | $ | 10,859 | $ | — | $ | 60,553 | ||||||||||||||||
|
Asset retirement costs
|
181,724 | 80,341 | — | 38,126 | — | (7,252 | ) | — | 292,939 | |||||||||||||||||||||||
|
2008
|
||||||||||||||||||||||||||||||||
|
Acquisitions:
|
||||||||||||||||||||||||||||||||
|
Proved
|
$ | 69,642 | $ | 4,938 | $ | — | $ | (500 | ) | $ | — | $ | — | $ | — | $ | 74,080 | |||||||||||||||
|
Unproved
|
75,437 | — | — | — | — | — | — | 75,437 | ||||||||||||||||||||||||
|
Exploration
|
382,019 | 253,940 | 192,588 | 293,031 | 107,338 | 256,068 | 27,457 | 1,512,441 | ||||||||||||||||||||||||
|
Development
|
2,200,910 | 580,406 | 667,860 | 588,539 | 364,421 | 98,074 | — | 4,500,210 | ||||||||||||||||||||||||
|
Costs incurred(1)
|
$ | 2,728,008 | $ | 839,284 | $ | 860,448 | $ | 881,070 | $ | 471,759 | $ | 354,142 | $ | 27,457 | $ | 6,162,168 | ||||||||||||||||
|
(1) Includes capitalized interest and asset retirement costs as
follows:
|
||||||||||||||||||||||||||||||||
|
Capitalized interest
|
$ | 20,267 | $ | 12,313 | $ | 7,646 | $ | 8,636 | $ | 703 | $ | 23,988 | $ | — | $ | 73,553 | ||||||||||||||||
|
Asset retirement costs
|
379,189 | 116,967 | — | (6,746 | ) | 11,817 | 12,664 | — | 513,891 | |||||||||||||||||||||||
|
2007
|
||||||||||||||||||||||||||||||||
|
Acquisitions:
|
||||||||||||||||||||||||||||||||
|
Proved
|
$ | 965,476 | $ | — | $ | 19,261 | $ | 10,530 | $ | — | $ | 9,259 | $ | — | $ | 1,004,526 | ||||||||||||||||
|
Unproved
|
— | 24,474 | — | 20,511 | 507 | — | — | 45,492 | ||||||||||||||||||||||||
|
Exploration
|
139,092 | 187,312 | 131,552 | 323,553 | 229,946 | 223,865 | — | 1,235,320 | ||||||||||||||||||||||||
|
Development
|
1,762,740 | 593,926 | 480,384 | 231,394 | 309,448 | 97,025 | — | 3,474,917 | ||||||||||||||||||||||||
|
Costs incurred(1)
|
$ | 2,867,308 | $ | 805,712 | $ | 631,197 | $ | 585,988 | $ | 539,901 | $ | 330,149 | $ | — | $ | 5,760,255 | ||||||||||||||||
|
(1) Includes capitalized interest and asset retirement costs as
follows:
|
||||||||||||||||||||||||||||||||
|
Capitalized interest
|
$ | 20,577 | $ | 13,106 | $ | 6,821 | $ | 6,447 | $ | 1,526 | $ | 20,980 | $ | — | $ | 69,457 | ||||||||||||||||
|
Asset retirement costs
|
271,183 | 117,456 | — | 37,866 | — | 12,863 | — | 439,368 | ||||||||||||||||||||||||
Capitalized
Costs
The following table sets forth the capitalized costs and
associated accumulated depreciation, depletion and amortization,
including impairments, relating to the Company’s oil and
gas production, exploration and development activities:
|
Other
|
||||||||||||||||||||||||||||||||
| United States | Canada | Egypt | Australia | North Sea | Argentina | International | Total | |||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||||||
|
Proved properties
|
$ | 22,776,452 | $ | 8,171,840 | $ | 4,271,326 | $ | 3,661,162 | $ | 3,477,421 | $ | 1,908,836 | $ | — | $ | 44,267,037 | ||||||||||||||||
|
Unproved properties
|
201,229 | 404,780 | 320,347 | 265,149 | 13,703 | 235,586 | 38,214 | 1,479,008 | ||||||||||||||||||||||||
| 22,977,681 | 8,576,620 | 4,591,673 | 3,926,311 | 3,491,124 | 2,144,422 | 38,214 | 45,746,045 | |||||||||||||||||||||||||
|
Accumulated DD&A
|
(13,269,941 | ) | (5,779,434 | ) | (2,319,647 | ) | (1,255,822 | ) | (1,844,424 | ) | (999,490 | ) | — | (25,468,758 | ) | |||||||||||||||||
| $ | 9,707,740 | $ | 2,797,186 | $ | 2,272,026 | $ | 2,670,489 | $ | 1,646,700 | $ | 1,144,932 | $ | 38,214 | $ | 20,277,287 | |||||||||||||||||
|
2008
|
||||||||||||||||||||||||||||||||
|
Proved properties
|
$ | 21,275,814 | $ | 7,748,591 | $ | 3,638,368 | $ | 3,121,845 | $ | 3,099,916 | $ | 1,754,747 | $ | — | $ | 40,639,281 | ||||||||||||||||
|
Unproved properties
|
381,258 | 312,616 | 231,169 | 110,348 | 15,724 | 221,775 | 27,457 | 1,300,347 | ||||||||||||||||||||||||
| 21,657,072 | 8,061,207 | 3,869,537 | 3,232,193 | 3,115,640 | 1,976,522 | 27,457 | 41,939,628 | |||||||||||||||||||||||||
|
Accumulated DD&A
|
(11,136,475 | ) | (3,970,016 | ) | (1,826,379 | ) | (1,069,933 | ) | (1,588,885 | ) | (856,380 | ) | — | (20,448,068 | ) | |||||||||||||||||
| $ | 10,520,597 | $ | 4,091,191 | $ | 2,043,158 | $ | 2,162,260 | $ | 1,526,755 | $ | 1,120,142 | $ | 27,457 | $ | 21,491,560 | |||||||||||||||||
F-50
Table of Contents
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, 2009, 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.
|
2006
|
||||||||||||||||||||
| Total | 2009 | 2008 | 2007 | and Prior | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Property acquisition costs
|
$ | 744,087 | $ | 171,910 | $ | 210,270 | $ | 150,597 | $ | 211,310 | ||||||||||
|
Exploration and development
|
650,383 | 380,108 | 196,133 | 17,911 | 56,231 | |||||||||||||||
|
Capitalized interest
|
84,538 | 25,269 | 35,135 | 8,443 | 15,691 | |||||||||||||||
|
Total
|
$ | 1,479,008 | $ | 577,287 | $ | 441,538 | $ | 176,951 | $ | 283,232 | ||||||||||
Proved
Undeveloped Reserves
The Company’s total estimated proved undeveloped reserves
of 731 MMboe as of December 31, 2009, increased by
54 MMboe over the 677 MMboe of PUD reserves estimated
at the end of 2008. During the year, Apache converted
39 MMboe of proved undeveloped reserves to proved developed
reserves through development drilling activity. In North America
we converted 22 MMboe with the remaining 17 MMboe in
our international areas.
During the year a total of $760 million was spent on
projects associated with reserves that were carried as PUD
reserves at the end of 2008. Not all of those expenditures
resulted in a conversion from proved undeveloped to proved
developed reserves during the year. We spent $264 million
on PUD reserve development activity in North America and
$496 million in the international areas, including
$230 million in Australia where the reserves for those
projects will be converted to developed in future years.
Oil
and Gas Reserve Information
In January 2009, the SEC issued Release
No. 33-8995
amending oil and gas reporting requirements under
Rule 4-10
of
Regulation S-X
and Industry Guide 2 in
Regulation S-K
and bringing full-cost accounting rules into alignment with the
revised disclosure requirements. 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.
In January 2010, the FASB issued ASU
No. 2010-03
,
which amends ASC Topic 932 to align the guidance with the
changes made by the SEC. The Company adopted these Modernization
Rules effective December 31, 2009, and the impact of the
adoption did not have a material impact on our results of
operations.
The new rules require the use of a 12-month average price,
instead of a single-day period end price, to calculate reserves.
Application of these rules resulted in the use of lower prices
at December 31, 2009, for both oil and gas than would have
resulted under the previous rules. Using these lower commodity
prices reduced the Company’s standardized measure and the
quantities of estimated proved reserves that were reported. The
effect of applying the new definition of reliable technology and
other non-price related aspects of the updated rules did not
have a significant impact on our estimated proved reserves at
December 31, 2009.
Apache’s 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 Apache’s 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
F-51
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
personnel are given security access rights consistent with their
assigned job function. Reserves are reviewed internally with
senior management and presented to Apache’s 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.
Apache’s Executive Vice President of Corporate Reservoir
Engineering, W. Kregg Olson, 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. Mr. Olson is a graduate of
Texas A&M University with a Bachelor of Science degree in
Petroleum Engineering. He has over 29 years of industry
experience, with the last 25 years focused on reservoir
engineering. He is a member of the Society of Petroleum
Engineers and is a Registered Professional Engineer in the state
of Oklahoma. Mr. Olson has held positions of increasing
responsibility within Apache’s corporate reservoir
engineering department since joining the company in 1992.
The estimate of reserves disclosed in this Annual Report on
Form 10-K
is prepared by the Company’s 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. These properties represented all material
fields, and over 85 percent of international properties and
new wells drilled during the year. During 2009, 2008, and 2007,
Ryder Scott’s review covered 79, 82 and 77 percent of
the Company’s worldwide estimated reserves value,
respectively. We have filed Ryder Scott’s independent
report as an exhibit to this
Form 10-K.
Ryder Scott opined that the overall proved reserves for the
reviewed properties as estimated by the Company are, in the
aggregate, reasonable, prepared in accordance with generally
accepted petroleum engineering and evaluation principles and
conform to the SEC’s definition of proved reserves as set
forth in
Rule 210.4-10(a)
of
Regulation S-X.
Ryder Scott has informed the Company that the tests and
procedures used during its reserves audit conform to the
Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information approved by the Society of Petroleum
Engineers. Paragraph 2.2(f) of the Standards Pertaining to
the Estimating and Auditing of Oil and Gas Reserves Information
defines a reserves audit as the process of reviewing certain of
the pertinent facts interpreted and assumptions made that have
resulted in an estimate of reserves prepared by others and the
rendering of an opinion about (1) the appropriateness of
the methodologies employed, (2) the adequacy and quality of
the data relied upon, (3) the depth and thoroughness of the
reserves estimation process, (4) the classification of
reserves appropriate to the relevant definitions used and
(5) the reasonableness of the estimated reserve quantities.
A reserve audit is not the same as a financial audit and is less
rigorous in nature than an independent reserve report where the
independent reserve engineer determines the reserves on his own.
F-52
Table of Contents
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, 2006
|
343,743 | 102,417 | 58,366 | 20,197 | 178,364 | 25,378 | 728,465 | 1,840,105 | 1,591,157 | 664,818 | 584,236 | 6,840 | 438,391 | 5,125,547 | 1,582,722 | |||||||||||||||||||||||||||||||||||||||||||||
|
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 | |||||||||||||||||||||||||||||||||||||||||||||
|
Proved undeveloped reserves:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
December 31, 2006
|
151,528 | 78,557 | 30,445 | 50,325 | 17,306 | 4,415 | 332,576 | 855,257 | 774,562 | 491,166 | 219,511 | — | 46,876 | 2,387,372 | 730,472 | |||||||||||||||||||||||||||||||||||||||||||||
|
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 | |||||||||||||||||||||||||||||||||||||||||||||
|
Total proved reserves:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Balance December 31, 2006
|
495,271 | 180,974 | 88,811 | 70,522 | 195,670 | 29,793 | 1,061,041 | 2,695,362 | 2,365,719 | 1,155,984 | 803,747 | 6,840 | 485,267 | 7,512,919 | 2,313,194 | |||||||||||||||||||||||||||||||||||||||||||||
|
Extensions, discoveries and other additions
|
31,504 | 8,083 | 34,148 | 9,812 | 28,622 | 3,353 | 115,522 | 217,560 | 122,745 | 178,978 | 414,896 | 169 | 91,236 | 1,025,584 | 286,452 | |||||||||||||||||||||||||||||||||||||||||||||
|
Purchases of minerals in-place
|
56,954 | 208 | 186 | 1,424 | — | — | 58,772 | 79,532 | 4,179 | — | — | — | — | 83,711 | 72,724 | |||||||||||||||||||||||||||||||||||||||||||||
|
Revisions of previous estimates
|
5,546 | (3,644 | ) | (6,369 | ) | — | — | 138 | (4,329 | ) | 8,881 | (15,889 | ) | (64,196 | ) | — | — | 287 | (70,917 | ) | (16,150 | ) | ||||||||||||||||||||||||||||||||||||||
|
Production
|
(35,938 | ) | (7,666 | ) | (22,168 | ) | (5,029 | ) | (19,575 | ) | (5,198 | ) | (95,574 | ) | (280,902 | ) | (141,697 | ) | (87,883 | ) | (71,149 | ) | (705 | ) | (73,330 | ) | (655,666 | ) | (204,850 | ) | ||||||||||||||||||||||||||||||
|
Sales of properties
|
(1,722 | ) | — | — | — | — | — | (1,722 | ) | (21,385 | ) | (1,529 | ) | — | — | — | — | (22,914 | ) | (5,541 | ) | |||||||||||||||||||||||||||||||||||||||
|
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 | |||||||||||||||||||||||||||||||||||||||||||||
Approximately 21 percent of our year-end 2009 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 13, under “Future Net Cash
Flows.”
F-53
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
Future
Net Cash Flows
Future cash inflows as of December 31, 2009 were calculated
using an average of oil and gas prices in effect on the first
day of each month in 2009, except where prices are defined by
contractual arrangements. Future cash inflows as of
December 31, 2008 and 2007 were estimated using oil and gas
prices in effect at the end of those years, 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 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 Company’s 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 thousands) | ||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||
|
Cash inflows
|
$ | 38,590,447 | $ | 15,698,458 | $ | 10,176,058 | $ | 11,095,515 | $ | 6,871,499 | $ | 2,433,895 | $ | 84,865,872 | ||||||||||||||
|
Production costs
|
(12,398,626 | ) | (7,315,631 | ) | (1,330,365 | ) | (2,536,780 | ) | (4,215,126 | ) | (859,680 | ) | (28,656,208 | ) | ||||||||||||||
|
Development costs
|
(3,176,983 | ) | (1,789,641 | ) | (1,511,999 | ) | (1,948,594 | ) | (780,109 | ) | (163,552 | ) | (9,370,878 | ) | ||||||||||||||
|
Income tax expense
|
(6,432,989 | ) | (1,010,049 | ) | (2,527,265 | ) | (1,852,361 | ) | (917,848 | ) | (350,332 | ) | (13,090,844 | ) | ||||||||||||||
|
Net cash flows
|
16,581,849 | 5,583,137 | 4,806,429 | 4,757,780 | 958,416 | 1,060,331 | 33,747,942 | |||||||||||||||||||||
|
10 percent discount rate
|
(8,554,656 | ) | (2,974,219 | ) | (1,364,915 | ) | (2,691,665 | ) | (70,195 | ) | (341,154 | ) | (15,996,804 | ) | ||||||||||||||
|
Discounted future net cash flows(1)
|
$ | 8,027,193 | $ | 2,608,918 | $ | 3,441,514 | $ | 2,066,115 | $ | 888,221 | $ | 719,177 | $ | 17,751,138 | ||||||||||||||
|
2008
|
||||||||||||||||||||||||||||
|
Cash inflows
|
$ | 33,163,869 | $ | 19,176,850 | $ | 8,197,873 | $ | 8,081,114 | $ | 7,245,187 | $ | 2,189,600 | $ | 78,054,493 | ||||||||||||||
|
Production costs
|
(12,106,876 | ) | (10,816,837 | ) | (1,364,304 | ) | (2,484,538 | ) | (4,007,188 | ) | (815,453 | ) | (31,595,196 | ) | ||||||||||||||
|
Development costs
|
(3,315,013 | ) | (2,038,896 | ) | (1,452,228 | ) | (1,704,401 | ) | (1,100,321 | ) | (180,926 | ) | (9,791,785 | ) | ||||||||||||||
|
Income tax expense
|
(4,559,309 | ) | (3,685,399 | ) | (1,857,758 | ) | (893,348 | ) | (1,043,415 | ) | (270,928 | ) | (12,310,157 | ) | ||||||||||||||
|
Net cash flows
|
13,182,671 | 2,635,718 | 3,523,583 | 2,998,827 | 1,094,263 | 922,293 | 24,357,355 | |||||||||||||||||||||
|
10 percent discount rate
|
(6,660,164 | ) | (1,567,388 | ) | (1,168,561 | ) | (1,515,430 | ) | (230,793 | ) | (267,187 | ) | (11,409,523 | ) | ||||||||||||||
|
Discounted future net cash flows(1)
|
$ | 6,522,507 | $ | 1,068,330 | $ | 2,355,022 | $ | 1,483,397 | $ | 863,470 | $ | 655,106 | $ | 12,947,832 | ||||||||||||||
|
2007
|
||||||||||||||||||||||||||||
|
Cash inflows
|
$ | 65,709,496 | $ | 30,593,185 | $ | 13,218,300 | $ | 11,109,570 | $ | 18,804,621 | $ | 2,196,765 | $ | 141,631,937 | ||||||||||||||
|
Production costs
|
(14,756,624 | ) | (10,615,928 | ) | (1,441,370 | ) | (2,645,871 | ) | (10,712,341 | ) | (640,022 | ) | (40,812,156 | ) | ||||||||||||||
|
Development costs
|
(3,570,210 | ) | (2,484,076 | ) | (1,332,022 | ) | (1,861,987 | ) | (872,754 | ) | (144,569 | ) | (10,265,618 | ) | ||||||||||||||
|
Income tax expense
|
(15,112,020 | ) | (5,049,325 | ) | (3,988,962 | ) | (1,820,006 | ) | (3,586,735 | ) | (364,839 | ) | (29,921,887 | ) | ||||||||||||||
|
Net cash flows
|
32,270,642 | 12,443,856 | 6,455,946 | 4,781,706 | 3,632,791 | 1,047,335 | 60,632,276 | |||||||||||||||||||||
|
10 percent discount rate
|
(16,958,060 | ) | (6,987,602 | ) | (2,087,773 | ) | (2,218,830 | ) | (1,338,178 | ) | (294,095 | ) | (29,884,538 | ) | ||||||||||||||
|
Discounted future net cash flows(1)
|
$ | 15,312,582 | $ | 5,456,254 | $ | 4,368,173 | $ | 2,562,876 | $ | 2,294,613 | $ | 753,240 | $ | 30,747,738 | ||||||||||||||
| (1) | Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $24.4 billion, $19.8 billion and $47.5 billion as of December 31, 2009, 2008 and 2007, respectively. |
F-54
Table of Contents
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, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
|
Sales, net of production costs
|
$ | (5,942,648 | ) | $ | (9,725,306 | ) | $ | (7,967,797 | ) | |||
|
Net change in prices and production costs
|
7,650,194 | (25,450,706 | ) | 15,869,295 | ||||||||
|
Discoveries and improved recovery, net of related costs
|
1,717,720 | 3,132,109 | 5,983,717 | |||||||||
|
Change in future development costs
|
1,238,102 | 1,335,971 | 289,764 | |||||||||
|
Revision of quantities
|
(1,257,800 | ) | 214,797 | (546,938 | ) | |||||||
|
Purchases of minerals in-place
|
529,713 | 1,675,599 | 1,842,457 | |||||||||
|
Accretion of discount
|
1,053,791 | 4,692,752 | 2,956,636 | |||||||||
|
Change in income taxes
|
822,732 | 7,820,734 | (5,848,139 | ) | ||||||||
|
Sales of properties
|
— | (653,782 | ) | (83,336 | ) | |||||||
|
Change in production rates and other
|
(1,008,498 | ) | (842,074 | ) | (1,117,310 | ) | ||||||
| $ | 4,803,306 | $ | (17,799,906 | ) | $ | 11,378,349 | ||||||
| 14. | SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited) |
| First | Second | Third | Fourth | Total | ||||||||||||||||
| (In thousands, except per share amounts) | ||||||||||||||||||||
|
2009
|
||||||||||||||||||||
|
Revenues
|
$ | 1,633,825 | $ | 2,093,378 | $ | 2,332,431 | $ | 2,555,192 | $ | 8,614,826 | ||||||||||
|
Expenses, net
|
3,390,765 | 1,648,658 | 1,890,415 | 1,969,386 | 8,899,224 | |||||||||||||||
|
Net income
|
$ | (1,756,940 | ) | $ | 444,720 | $ | 442,016 | $ | 585,806 | $ | (284,398 | ) | ||||||||
|
Income attributable to common stock
|
$ | (1,758,360 | ) | $ | 443,300 | $ | 440,596 | $ | 582,772 | $ | (291,692 | ) | ||||||||
|
Net income per common share(1):
|
||||||||||||||||||||
|
Basic
|
$ | (5.25 | ) | $ | 1.32 | $ | 1.31 | $ | 1.73 | $ | (.87 | ) | ||||||||
|
Diluted
|
$ | (5.25 | ) | $ | 1.31 | $ | 1.30 | $ | 1.72 | $ | (.87 | ) | ||||||||
|
2008
|
||||||||||||||||||||
|
Revenues
|
$ | 3,187,741 | $ | 3,900,191 | $ | 3,364,884 | $ | 1,936,934 | $ | 12,389,750 | ||||||||||
|
Expenses, net
|
2,166,228 | 2,454,962 | 2,174,059 | 4,882,547 | 11,677,796 | |||||||||||||||
|
Net income
|
$ | 1,021,513 | $ | 1,445,229 | $ | 1,190,825 | $ | (2,945,613 | ) | $ | 711,954 | |||||||||
|
Income attributable to common stock
|
$ | 1,020,093 | $ | 1,443,809 | $ | 1,189,405 | $ | (2,947,033 | ) | $ | 706,274 | |||||||||
|
Net income per common share(1):
|
||||||||||||||||||||
|
Basic
|
$ | 3.06 | $ | 4.32 | $ | 3.55 | $ | (8.80 | ) | $ | 2.11 | |||||||||
|
Diluted
|
$ | 3.03 | $ | 4.28 | $ | 3.52 | $ | (8.80 | ) | $ | 2.09 | |||||||||
| (1) | The sum of the individual quarterly net income 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. |
F-55
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
| 15. | 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. Issuers with no independent
operations qualify as “finance subsidiaries” and are
exempt from the reporting requirements. Apache Finance Australia
and Apache Finance Canada qualified as “finance
subsidiaries” until Apache, during 2001, contributed stock
of its Australian and Canadian operating subsidiaries to Apache
Finance Australia and Apache Finance Canada, respectively.
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.
Each of the companies presented in the condensed consolidating
financial statements is wholly owned and has been consolidated
in Apache Corporation’s consolidated financial statements
for all 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 and, beginning in 2001, also by Apache
North America, Inc. 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.
F-56
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
CONDENSED
CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2009
For the Year Ended December 31, 2009
|
All Other
|
||||||||||||||||||||
|
Subsidiaries
|
||||||||||||||||||||
|
Apache
|
Apache
|
of Apache
|
Reclassifications
|
|||||||||||||||||
| Corporation | Finance Canada | Corporation | & Eliminations | Consolidated | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
REVENUES AND OTHER:
|
||||||||||||||||||||
|
Oil and gas production revenues
|
$ | 2,769,642 | $ | — | $ | 5,804,285 | $ | — | $ | 8,573,927 | ||||||||||
|
Equity in net income (loss) of affiliates
|
235,554 | (448,596 | ) | 167,804 | 45,238 | — | ||||||||||||||
|
Other
|
(3,009 | ) | 58,848 | (10,831 | ) | (4,109 | ) | 40,899 | ||||||||||||
| 3,002,187 | (389,748 | ) | 5,961,258 | 41,129 | 8,614,826 | |||||||||||||||
|
OPERATING EXPENSES:
|
||||||||||||||||||||
|
Depreciation, depletion and amortization
|
2,096,782 | — | 3,116,442 | — | 5,213,224 | |||||||||||||||
|
Asset retirement obligation accretion
|
63,055 | — | 41,760 | — | 104,815 | |||||||||||||||
|
Lease operating expenses
|
690,760 | — | 971,380 | — | 1,662,140 | |||||||||||||||
|
Gathering and transportation
|
34,151 | — | 108,548 | — | 142,699 | |||||||||||||||
|
Taxes other than income
|
100,081 | — | 479,355 | — | 579,436 | |||||||||||||||
|
General and administrative
|
274,838 | — | 73,154 | (4,109 | ) | 343,883 | ||||||||||||||
|
Financing costs, net
|
228,268 | (15,708 | ) | 29,678 | — | 242,238 | ||||||||||||||
| 3,487,935 | (15,708 | ) | 4,820,317 | (4,109 | ) | 8,288,435 | ||||||||||||||
|
INCOME (LOSS) BEFORE INCOME TAXES
|
(485,748 | ) | (374,040 | ) | 1,140,941 | 45,238 | 326,391 | |||||||||||||
|
Provision (benefit) for income taxes
|
(201,350 | ) | (93,248 | ) | 905,387 | — | 610,789 | |||||||||||||
|
NET INCOME
|
(284,398 | ) | (280,792 | ) | 235,554 | 45,238 | (284,398 | ) | ||||||||||||
|
Preferred stock dividends
|
7,294 | — | — | — | 7,294 | |||||||||||||||
|
INCOME ATTRIBUTABLE TO COMMON STOCK
|
$ | (291,692 | ) | $ | (280,792 | ) | $ | 235,554 | $ | 45,238 | $ | (291,692 | ) | |||||||
F-57
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
CONDENSED
CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2008
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 thousands) | ||||||||||||||||||||||||||||
|
REVENUES AND OTHER:
|
||||||||||||||||||||||||||||
|
Oil and gas production revenues
|
$ | 4,552,515 | $ | — | $ | — | $ | — | $ | 7,821,713 | $ | (46,389 | ) | $ | 12,327,839 | |||||||||||||
|
Equity in net income (loss) of affiliates
|
525,829 | 71,228 | 67,820 | (156,540 | ) | 88,407 | (596,744 | ) | — | |||||||||||||||||||
|
Other
|
25,876 | (30,643 | ) | 30,542 | 58,832 | (19,006 | ) | (3,690 | ) | 61,911 | ||||||||||||||||||
| 5,104,220 | 40,585 | 98,362 | (97,708 | ) | 7,891,114 | (646,823 | ) | 12,389,750 | ||||||||||||||||||||
|
OPERATING EXPENSES:
|
||||||||||||||||||||||||||||
|
Depreciation, depletion and amortization
|
3,276,414 | — | — | — | 4,573,844 | — | 7,850,258 | |||||||||||||||||||||
|
Asset retirement obligation accretion
|
66,189 | — | — | — | 35,159 | — | 101,348 | |||||||||||||||||||||
|
Lease operating expenses
|
821,150 | — | — | — | 1,088,475 | — | 1,909,625 | |||||||||||||||||||||
|
Gathering and transportation
|
38,606 | — | — | — | 164,274 | (46,389 | ) | 156,491 | ||||||||||||||||||||
|
Taxes other than income
|
169,061 | — | — | — | 815,746 | — | 984,807 | |||||||||||||||||||||
|
General and administrative
|
223,467 | — | — | — | 69,016 | (3,689 | ) | 288,794 | ||||||||||||||||||||
|
Financing costs, net
|
150,202 | (11,050 | ) | 18,046 | (5,585 | ) | 14,422 | — | 166,035 | |||||||||||||||||||
| 4,745,089 | (11,050 | ) | 18,046 | (5,585 | ) | 6,760,936 | (50,078 | ) | 11,457,358 | |||||||||||||||||||
|
INCOME (LOSS) BEFORE INCOME TAXES
|
359,131 | 51,635 | 80,316 | (92,123 | ) | 1,130,178 | (596,745 | ) | 932,392 | |||||||||||||||||||
|
Provision (benefit) for income taxes
|
(352,823 | ) | (11,939 | ) | 9,088 | (28,236 | ) | 604,348 | — | 220,438 | ||||||||||||||||||
|
NET INCOME
|
711,954 | 63,574 | 71,228 | (63,887 | ) | 525,830 | (596,745 | ) | 711,954 | |||||||||||||||||||
|
Preferred stock dividends
|
5,680 | — | — | — | — | — | 5,680 | |||||||||||||||||||||
|
INCOME ATTRIBUTABLE TO COMMON STOCK
|
$ | 706,274 | $ | 63,574 | $ | 71,228 | $ | (63,887 | ) | $ | 525,830 | $ | (596,745 | ) | $ | 706,274 | ||||||||||||
F-58
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
CONDENSED
CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2007
For the Year Ended December 31, 2007
|
All Other
|
||||||||||||||||||||||||||||
|
Subsidiaries
|
||||||||||||||||||||||||||||
|
Apache
|
Apache
|
Apache
|
Apache
|
of Apache
|
Reclassifications
|
|||||||||||||||||||||||
| Corporation | North America | Finance Australia | Finance Canada | Corporation | & Eliminations | Consolidated | ||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||
|
REVENUES AND OTHER:
|
||||||||||||||||||||||||||||
|
Oil and gas production revenues
|
$ | 4,243,362 | $ | — | $ | — | $ | — | $ | 5,827,276 | $ | (108,656 | ) | $ | 9,961,982 | |||||||||||||
|
Equity in net income (loss) of affiliates
|
1,704,390 | 49,183 | 60,985 | 141,181 | — | (1,955,739 | ) | — | ||||||||||||||||||||
|
Other
|
13,000 | — | (259 | ) | (59,160 | ) | 87,879 | (3,690 | ) | 37,770 | ||||||||||||||||||
| 5,960,752 | 49,183 | 60,726 | 82,021 | 5,915,155 | (2,068,085 | ) | 9,999,752 | |||||||||||||||||||||
|
OPERATING EXPENSES:
|
||||||||||||||||||||||||||||
|
Depreciation, depletion and amortization
|
1,070,058 | — | — | — | 1,277,733 | — | 2,347,791 | |||||||||||||||||||||
|
Asset retirement obligation accretion
|
70,005 | — | — | — | 26,433 | — | 96,438 | |||||||||||||||||||||
|
Lease operating expenses
|
801,937 | — | — | — | 850,918 | — | 1,652,855 | |||||||||||||||||||||
|
Gathering and transportation
|
38,084 | — | — | — | 207,979 | (108,656 | ) | 137,407 | ||||||||||||||||||||
|
Taxes other than income
|
160,971 | — | — | — | 436,676 | — | 597,647 | |||||||||||||||||||||
|
General and administrative
|
223,229 | — | — | — | 55,526 | (3,690 | ) | 275,065 | ||||||||||||||||||||
|
Financing costs, net
|
237,892 | — | 18,076 | (2,711 | ) | (33,320 | ) | — | 219,937 | |||||||||||||||||||
| 2,602,176 | — | 18,076 | (2,711 | ) | 2,821,945 | (112,346 | ) | 5,327,140 | ||||||||||||||||||||
|
INCOME (LOSS) BEFORE INCOME TAXES
|
3,358,576 | 49,183 | 42,650 | 84,732 | 3,093,210 | (1,955,739 | ) | 4,672,612 | ||||||||||||||||||||
|
Provision (benefit) for income taxes
|
546,218 | — | (6,533 | ) | (16,511 | ) | 1,337,080 | — | 1,860,254 | |||||||||||||||||||
|
NET INCOME
|
2,812,358 | 49,183 | 49,183 | 101,243 | 1,756,130 | (1,955,739 | ) | 2,812,358 | ||||||||||||||||||||
|
Preferred stock dividends
|
5,680 | — | — | — | — | — | 5,680 | |||||||||||||||||||||
|
INCOME ATTRIBUTABLE TO COMMON STOCK
|
$ | 2,806,678 | $ | 49,183 | $ | 49,183 | $ | 101,243 | $ | 1,756,130 | $ | (1,955,739 | ) | $ | 2,806,678 | |||||||||||||
F-59
Table of Contents
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 thousands) | ||||||||||||||||||||
|
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
|
$ | 1,856,320 | $ | (14,734 | ) | $ | 2,382,057 | $ | — | $ | 4,223,643 | |||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||||||||||
|
Additions to oil and gas property
|
(1,008,099 | ) | — | (2,317,611 | ) | — | (3,325,710 | ) | ||||||||||||
|
Additions to gathering, transmission and processing facilities
|
— | — | (305,389 | ) | — | (305,389 | ) | |||||||||||||
|
Acquisitions, other
|
(195,966 | ) | — | (114,506 | ) | — | (310,472 | ) | ||||||||||||
|
Short-term investments
|
791,999 | — | — | — | 791,999 | |||||||||||||||
|
Restricted cash
|
13,880 | — | — | — | 13,880 | |||||||||||||||
|
Proceeds from sale of oil and gas properties
|
162 | — | 2,105 | — | 2,267 | |||||||||||||||
|
Investment in and advances to subsidiaries, net
|
(657,004 | ) | — | — | 657,004 | — | ||||||||||||||
|
Other, net
|
(38,526 | ) | — | (75,475 | ) | — | (114,001 | ) | ||||||||||||
|
NET CASH USED IN INVESTING ACTIVITIES
|
(1,093,554 | ) | — | (2,810,876 | ) | 657,004 | (3,247,426 | ) | ||||||||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||||||||||
|
Commercial paper, credit facility and bank notes, net
|
1,335 | (2,711 | ) | 903,003 | (653,458 | ) | 248,169 | |||||||||||||
|
Fixed-rate debt borrowings
|
— | — | — | — | — | |||||||||||||||
|
Payments on fixed-rate notes
|
— | — | (100,000 | ) | — | (100,000 | ) | |||||||||||||
|
Dividends paid
|
(208,603 | ) | — | — | — | (208,603 | ) | |||||||||||||
|
Common stock activity
|
28,495 | 17,828 | (14,282 | ) | (3,546 | ) | 28,495 | |||||||||||||
|
Redemption of preferred stock
|
(98,387 | ) | — | — | — | (98,387 | ) | |||||||||||||
|
Treasury stock activity, net
|
5,620 | — | — | — | 5,620 | |||||||||||||||
|
Cost of debt and equity transactions
|
(655 | ) | — | — | — | (655 | ) | |||||||||||||
|
Other
|
14,132 | — | 1,679 | — | 15,811 | |||||||||||||||
|
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
(258,063 | ) | 15,117 | 790,400 | (657,004 | ) | (109,550 | ) | ||||||||||||
|
NET INCREASE IN CASH AND CASH EQUIVALENTS
|
504,703 | 383 | 361,581 | — | 866,667 | |||||||||||||||
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
142,026 | 1,714 | 1,037,710 | — | 1,181,450 | |||||||||||||||
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
$ | 646,729 | $ | 2,097 | $ | 1,399,291 | $ | — | $ | 2,048,117 | ||||||||||
F-60
Table of Contents
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 thousands) | ||||||||||||||||||||||||||||
|
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
|
$ | 1,590,113 | $ | (1,038 | ) | $ | (12,239 | ) | $ | 3,255 | $ | 5,485,253 | $ | — | $ | 7,065,344 | ||||||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||||||||||||||||||
|
Additions to oil and gas property
|
(1,387,736 | ) | — | — | — | (3,755,867 | ) | — | (5,143,603 | ) | ||||||||||||||||||
|
Additions to gathering, transmission and processing facilities
|
— | — | — | — | (679,405 | ) | — | (679,405 | ) | |||||||||||||||||||
|
Acquisitions, other
|
(145,400 | ) | — | — | — | (4,438 | ) | — | (149,838 | ) | ||||||||||||||||||
|
Short-term investments
|
(791,999 | ) | — | — | — | — | — | (791,999 | ) | |||||||||||||||||||
|
Restricted cash
|
(13,880 | ) | — | — | — | — | — | (13,880 | ) | |||||||||||||||||||
|
Proceeds from sales of oil and gas properties
|
206,047 | — | — | — | 101,927 | — | 307,974 | |||||||||||||||||||||
|
Investment in and advances to subsidiaries, net
|
(198,164 | ) | (12,977 | ) | — | — | — | 211,141 | — | |||||||||||||||||||
|
Other, net
|
384,782 | — | — | — | (449,008 | ) | — | (64,226 | ) | |||||||||||||||||||
|
NET CASH USED IN INVESTING ACTIVITIES
|
(1,946,350 | ) | (12,977 | ) | — | — | (4,786,791 | ) | 211,141 | (6,534,977 | ) | |||||||||||||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||||||||||||||||||
|
Commercial paper, credit facility and bank notes, net
|
(138,231 | ) | (6,872 | ) | (737 | ) | (2,202 | ) | 153,117 | (104,878 | ) | (99,803 | ) | |||||||||||||||
|
Fixed-rate debt borrowings
|
796,315 | — | — | — | — | — | 796,315 | |||||||||||||||||||||
|
Payments on fixed-rate notes
|
— | — | — | — | (353 | ) | — | (353 | ) | |||||||||||||||||||
|
Dividends paid
|
(239,358 | ) | — | — | — | — | — | (239,358 | ) | |||||||||||||||||||
|
Common stock activity
|
31,513 | 19,977 | 12,977 | (1,090 | ) | 74,399 | (106,263 | ) | 31,513 | |||||||||||||||||||
|
Treasury stock activity, net
|
4,498 | — | — | — | — | — | 4,498 | |||||||||||||||||||||
|
Cost of debt and equity transactions
|
(7,050 | ) | — | — | — | — | — | (7,050 | ) | |||||||||||||||||||
|
Other
|
46,951 | — | — | — | (7,453 | ) | — | 39,498 | ||||||||||||||||||||
|
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
494,638 | 13,105 | 12,240 | (3,292 | ) | 219,710 | (211,141 | ) | 525,260 | |||||||||||||||||||
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
138,401 | (910 | ) | 1 | (37 | ) | 918,172 | — | 1,055,627 | |||||||||||||||||||
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
3,626 | 484 | 1 | 1,751 | 119,961 | — | 125,823 | |||||||||||||||||||||
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
$ | 142,027 | $ | (426 | ) | $ | 2 | $ | 1,714 | $ | 1,038,133 | $ | — | $ | 1,181,450 | |||||||||||||
F-61
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
CONDENSED
CONSOLIDATING STATEMENT OF CASH FLOWS
For the
Year Ended December 31, 2007
|
All Other
|
||||||||||||||||||||||||||||
|
Subsidiaries
|
||||||||||||||||||||||||||||
|
Apache
|
Apache
|
Apache
|
Apache
|
of Apache
|
Reclassifications
|
|||||||||||||||||||||||
| Corporation | North America | Finance Australia | Finance Canada | Corporation | & Eliminations | Consolidated | ||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||
|
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
|
$ | 3,536,130 | $ | — | $ | (18,622 | ) | $ | (990,754 | ) | $ | 3,150,679 | $ | — | $ | 5,677,433 | ||||||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||||||||||||||||||
|
Additions to oil and gas property
|
(1,748,051 | ) | — | — | — | (2,552,993 | ) | — | (4,301,044 | ) | ||||||||||||||||||
|
Additions to gathering, transmission and processing facilities
|
— | — | — | — | (480,936 | ) | — | (480,936 | ) | |||||||||||||||||||
|
Acquisition of Anadarko properties
|
(1,004,593 | ) | — | — | — | — | — | (1,004,593 | ) | |||||||||||||||||||
|
Acquisitions, other
|
(1,062 | ) | — | — | — | (19,301 | ) | — | (20,363 | ) | ||||||||||||||||||
|
Proceeds from sales of oil and gas properties
|
4,623 | — | — | — | 62,860 | — | 67,483 | |||||||||||||||||||||
|
Investment in and advances to subsidiaries, net
|
(1,123,148 | ) | (24,977 | ) | — | — | (1,181,454 | ) | 2,329,579 | — | ||||||||||||||||||
|
Other, net
|
(71,752 | ) | — | — | — | (134,724 | ) | — | (206,476 | ) | ||||||||||||||||||
|
NET CASH USED IN INVESTING ACTIVITIES
|
(3,943,983 | ) | (24,977 | ) | — | — | (4,306,548 | ) | 2,329,579 | (5,945,929 | ) | |||||||||||||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||||||||||||||||||
|
Commercial paper, credit facility and bank notes, net
|
(1,431,714 | ) | — | 163,645 | (377 | ) | 93,696 | (237,500 | ) | (1,412,250 | ) | |||||||||||||||||
|
Fixed-rate debt borrowings
|
1,992,290 | — | — | — | — | — | 1,992,290 | |||||||||||||||||||||
|
Payments on fixed-rate notes
|
— | — | (170,000 | ) | — | (3,000 | ) | — | (173,000 | ) | ||||||||||||||||||
|
Dividends paid
|
(204,753 | ) | — | — | — | — | — | (204,753 | ) | |||||||||||||||||||
|
Common stock activity
|
29,682 | 24,977 | 24,977 | 992,881 | 1,049,244 | (2,092,079 | ) | 29,682 | ||||||||||||||||||||
|
Treasury stock activity, net
|
14,279 | — | — | — | — | — | 14,279 | |||||||||||||||||||||
|
Cost of debt and equity transactions
|
(18,179 | ) | — | — | — | — | — | (18,179 | ) | |||||||||||||||||||
|
Other
|
25,726 | — | — | — | — | — | 25,726 | |||||||||||||||||||||
|
NET CASH PROVIDED BY FINANCING ACTIVITIES
|
407,331 | 24,977 | 18,622 | 992,504 | 1,139,940 | (2,329,579 | ) | 253,795 | ||||||||||||||||||||
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
(522 | ) | — | — | 1,750 | (15,929 | ) | — | (14,701 | ) | ||||||||||||||||||
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
4,148 | — | 1 | 1 | 136,374 | — | 140,524 | |||||||||||||||||||||
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
$ | 3,626 | $ | — | $ | 1 | $ | 1,751 | $ | 120,445 | $ | — | $ | 125,823 | ||||||||||||||
F-62
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
CONDENSED
CONSOLIDATING BALANCE SHEET
December 31, 2009
December 31, 2009
|
All Other
|
||||||||||||||||||||
|
Subsidiaries
|
||||||||||||||||||||
|
Apache
|
Apache
|
of Apache
|
Reclassifications
|
|||||||||||||||||
| Corporation | Finance Canada | Corporation | & Eliminations | Consolidated | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
ASSETS
|
||||||||||||||||||||
|
CURRENT ASSETS:
|
||||||||||||||||||||
|
Cash and cash equivalents
|
$ | 646,728 | $ | 2,097 | $ | 1,399,292 | $ | — | $ | 2,048,117 | ||||||||||
|
Receivables, net of allowance
|
574,427 | — | 971,272 | — | 1,545,699 | |||||||||||||||
|
Inventories
|
50,946 | — | 482,305 | — | 533,251 | |||||||||||||||
|
Drilling advances
|
13,103 | 1,095 | 216,535 | — | 230,733 | |||||||||||||||
|
Prepaid taxes
|
142,675 | — | 3,978 | — | 146,653 | |||||||||||||||
|
Prepaid assets and other
|
(158,358 | ) | — | 239,754 | — | 81,396 | ||||||||||||||
| 1,269,521 | 3,192 | 3,313,136 | — | 4,585,849 | ||||||||||||||||
|
PROPERTY AND EQUIPMENT, NET
|
9,163,228 | — | 13,737,387 | — | 22,900,615 | |||||||||||||||
|
OTHER ASSETS:
|
||||||||||||||||||||
|
Intercompany receivable, net
|
1,839,229 | — | (348,352 | ) | (1,490,877 | ) | — | |||||||||||||
|
Equity in affiliates
|
11,243,366 | 980,709 | 98,615 | (12,322,690 | ) | — | ||||||||||||||
|
Restricted cash
|
— | — | — | — | — | |||||||||||||||
|
Goodwill, net
|
— | — | 189,252 | — | 189,252 | |||||||||||||||
|
Deferred charges and other
|
133,556 | 1,003,037 | 373,434 | (1,000,000 | ) | 510,027 | ||||||||||||||
| $ | 23,648,900 | $ | 1,986,938 | $ | 17,363,472 | $ | (14,813,567 | ) | $ | 28,185,743 | ||||||||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||||||||||||||
|
CURRENT LIABILITIES:
|
||||||||||||||||||||
|
Accounts payable
|
$ | 258,363 | $ | (88 | ) | $ | 1,629,166 | $ | (1,490,877 | ) | $ | 396,564 | ||||||||
|
Accrued exploration and development
|
246,707 | — | 676,377 | — | 923,084 | |||||||||||||||
|
Current debt
|
— | — | 117,326 | — | 117,326 | |||||||||||||||
|
Asset retirement obligations
|
146,654 | — | — | — | 146,654 | |||||||||||||||
|
Derivative instruments
|
109,990 | — | 18,229 | — | 128,219 | |||||||||||||||
|
Other accrued expenses
|
237,006 | 6,121 | 437,584 | — | 680,711 | |||||||||||||||
| 998,720 | 6,033 | 2,878,682 | (1,490,877 | ) | 2,392,558 | |||||||||||||||
|
LONG-TERM DEBT
|
4,062,339 | 647,152 | 240,899 | — | 4,950,390 | |||||||||||||||
|
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
|
||||||||||||||||||||
|
Income taxes
|
1,306,100 | 4,429 | 1,454,372 | — | 2,764,901 | |||||||||||||||
|
Asset retirement obligation
|
817,507 | — | 819,850 | — | 1,637,357 | |||||||||||||||
|
Other
|
685,612 | 250,000 | 726,304 | (1,000,000 | ) | 661,916 | ||||||||||||||
| 2,809,219 | 254,429 | 3,000,526 | (1,000,000 | ) | 5,064,174 | |||||||||||||||
|
COMMITMENTS AND CONTINGENCIES
|
||||||||||||||||||||
|
SHAREHOLDERS’ EQUITY
|
15,778,622 | 1,079,324 | 11,243,365 | (12,322,690 | ) | 15,778,621 | ||||||||||||||
| $ | 23,648,900 | $ | 1,986,938 | $ | 17,363,472 | $ | (14,813,567 | ) | $ | 28,185,743 | ||||||||||
F-63
Table of Contents
APACHE
CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
CONDENSED
CONSOLIDATING BALANCE SHEET
December 31, 2008
December 31, 2008
|
All Other
|
||||||||||||||||||||||||||||
|
Subsidiaries
|
||||||||||||||||||||||||||||
|
Apache
|
Apache
|
Apache
|
Apache
|
of Apache
|
Reclassifications
|
|||||||||||||||||||||||
| Corporation | North America | Finance Australia | Finance Canada | Corporation | & Eliminations | Consolidated | ||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||
|
ASSETS
|
||||||||||||||||||||||||||||
|
CURRENT ASSETS:
|
||||||||||||||||||||||||||||
|
Cash and cash equivalents
|
$ | 142,026 | $ | — | $ | 2 | $ | 1,714 | $ | 1,037,708 | $ | — | $ | 1,181,450 | ||||||||||||||
|
Short-term investments
|
791,899 | — | — | — | 100 | — | 791,999 | |||||||||||||||||||||
|
Receivables, net of allowance
|
514,174 | — | — | 1,095 | 841,710 | — | 1,356,979 | |||||||||||||||||||||
|
Inventories
|
59,106 | — | — | — | 439,461 | — | 498,567 | |||||||||||||||||||||
|
Drilling advances
|
156,977 | — | — | — | (63,600 | ) | — | 93,377 | ||||||||||||||||||||
|
Prepaid taxes
|
280,122 | — | — | 1,786 | 21,295 | — | 303,203 | |||||||||||||||||||||
|
Prepaid assets and other
|
19,857 | — | — | — | 205,542 | — | 225,399 | |||||||||||||||||||||
| 1,964,161 | — | 2 | 4,595 | 2,482,216 | — | 4,450,974 | ||||||||||||||||||||||
|
PROPERTY AND EQUIPMENT, NET
|
9,970,619 | — | — | — | 13,987,898 | — | 23,958,517 | |||||||||||||||||||||
|
OTHER ASSETS:
|
||||||||||||||||||||||||||||
|
Intercompany receivable, net
|
1,185,771 | — | — | — | — | (1,185,771 | ) | — | ||||||||||||||||||||
|
Restricted cash
|
13,880 | — | — | — | — | — | 13,880 | |||||||||||||||||||||
|
Goodwill, net
|
— | — | — | — | 189,252 | — | 189,252 | |||||||||||||||||||||
|
Equity in affiliates
|
12,919,395 | 510,620 | 714,092 | 1,556,673 | (157,276 | ) | (15,543,504 | ) | — | |||||||||||||||||||
|
Deferred charges and other
|
212,635 | — | — | 1,003,353 | 357,874 | (1,000,000 | ) | 573,862 | ||||||||||||||||||||
| $ | 26,266,461 | $ | 510,620 | $ | 714,094 | $ | 2,564,621 | $ | 16,859,964 | $ | (17,729,275 | ) | $ | 29,186,485 | ||||||||||||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||||||||||||||||||||||
|
CURRENT LIABILITIES:
|
||||||||||||||||||||||||||||
|
Accounts payable
|
$ | 2,059,459 | $ | — | $ | — | $ | — | $ | (324,743 | ) | $ | (1,185,771 | ) | $ | 548,945 | ||||||||||||
|
Accrued exploration and development
|
279,746 | — | — | — | 685,113 | — | 964,859 | |||||||||||||||||||||
|
Current debt
|
— | — | 99,977 | — | 12,621 | — | 112,598 | |||||||||||||||||||||
|
Asset retirement obligations
|
339,155 | — | — | — | — | — | 339,155 | |||||||||||||||||||||
|
Derivative instruments
|
— | — | — | — | — | — | — | |||||||||||||||||||||
|
Other accrued expenses
|
281,885 | (10,097 | ) | 165,432 | 290,587 | (172,929 | ) | — | 554,878 | |||||||||||||||||||
| 2,960,245 | (10,097 | ) | 265,409 | 290,587 | 200,062 | (1,185,771 | ) | 2,520,435 | ||||||||||||||||||||
|
LONG-TERM DEBT
|
4,061,005 | — | — | 647,071 | 100,899 | — | 4,808,975 | |||||||||||||||||||||
|
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
|
||||||||||||||||||||||||||||
|
Income taxes
|
1,599,539 | — | (31,292 | ) | 3,548 | 1,594,862 | — | 3,166,657 | ||||||||||||||||||||
|
Asset retirement obligation
|
844,126 | — | — | — | 711,403 | — | 1,555,529 | |||||||||||||||||||||
|
Other
|
292,825 | 30,643 | (30,643 | ) | — | 1,333,343 | (1,000,000 | ) | 626,168 | |||||||||||||||||||
| 2,736,490 | 30,643 | (61,935 | ) | 3,548 | 3,639,608 | (1,000,000 | ) | 5,348,354 | ||||||||||||||||||||
|
COMMITMENTS AND CONTINGENCIES
|
||||||||||||||||||||||||||||
|
SHAREHOLDERS’ EQUITY
|
16,508,721 | 490,074 | 510,620 | 1,623,415 | 12,919,395 | (15,543,504 | ) | 16,508,721 | ||||||||||||||||||||
| $ | 26,266,461 | $ | 510,620 | $ | 714,094 | $ | 2,564,621 | $ | 16,859,964 | $ | (17,729,275 | ) | $ | 29,186,485 | ||||||||||||||
F-64
Table of Contents
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, Former 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
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 (Principal Financial
Officer)
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 and
Technology 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
Sarah B. Teslik
Senior Vice President —
Policy and Governance
John R. Bedingfield
Vice President —
Worldwide Exploration and New
Ventures
Thomas P. Chambers
Vice President — Planning
and Investor Relations
Matthew W. Dundrea
Vice President and Treasurer
Robert J. Dye
Vice President —
Corporate Services
David L. French
Vice President — Business
Development
Margie Harris
Vice President — Human
Resources
Rebecca A. Hoyt
Vice President and Controller
Janine J. McArdle
Vice President — Oil and
Gas Marketing
Aaron S. G. Merrick
Vice President —
Information Technology
Urban F. O’Brien
Vice President —
Government Affairs
Jon W. Sauer
Vice President — Tax
Cheri L. Peper
Corporate Secretary
Table of Contents
Shareholder
Information
Stock Data
|
Dividends
|
||||||||||||||||
| Price Range | per Share | |||||||||||||||
| High | Low | Declared | Paid | |||||||||||||
|
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 | ||||||||||||
|
2008
|
||||||||||||||||
|
First Quarter
|
$ | 122.34 | $ | 84.52 | $ | .25 | $ | .25 | ||||||||
|
Second Quarter
|
149.23 | 117.65 | .15 | .15 | ||||||||||||
|
Third Quarter
|
145.00 | 94.82 | .15 | .15 | ||||||||||||
|
Fourth Quarter
|
103.17 | 57.11 | .15 | .15 | ||||||||||||
The Company has paid cash dividends on its common stock for 45
consecutive years through December 31, 2009. Future
dividend payments will depend upon the Company’s 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, 2009, the Company’s shares of common
stock outstanding were held by approximately
5,800 shareholders of record and 442,000 beneficial owners.
Also listed on the New York Stock Exchange are:
| • | Apache Finance Canada’s 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 Company’s 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 Company’s
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 Company’s stock
transfer agent, Wells Fargo Bank, N.A.
Annual
Meeting
Apache will hold its annual meeting of shareholders on Thursday,
May 6, 2010, 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 Apache’s
Public and International Affairs Department, 2000 Post Oak
Boulevard, Suite 100, Houston, Texas,
77056-4400,
by calling
(713) 296-6157
or by registering on Apache’s web site: www.apachecorp.com
Form 10-K
Request
Shareholders and other persons interested in obtaining, without
cost, a copy of the Company’s
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
Thomas P. Chambers, Vice President, Planning and Investor
Relations, at
(713) 296-6685.
Members of the news media and others seeking information about
the Company should contact Apache’s Public and
International Affairs Department at
(713) 296-7276.
Web site: www.apachecorp.com
Table of Contents
Index to
Exhibits
|
Exhibit
|
||||||
|
No.
|
Description
|
|||||
| *3 | .1 | — | Restated Certificate of Incorporation of Registrant, dated February 23, 2010, as filed with the Secretary of State of Delaware on February 23, 2010. | |||
| 3 | .2 | — | Bylaws of Registrant, as amended August 6, 2009 (incorporated by reference to Exhibit 3.2 to Registrant’s Quarterly Report on Form 10-K for quarter ended June 30, 2009, SEC File No. 001-4300). | |||
| 4 | .1 | — | Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 001-4300). | |||
| 4 | .2 | — | 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 Registrant’s common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit(a) to Registrant’s Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 001-4300). | |||
| 4 | .3 | — | 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 Registrant’s Amendment No. 1 to Registration Statement on Form 8-A, dated January 31, 2006, SEC File No. 001-4300). | |||
| 4 | .4 | — | 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 Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536). | |||
| 4 | .5 | — | 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 Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536). | |||
| 4 | .6 | — | 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 Registrant’s Registration Statement on Form S-3, dated November 12, 1997, Reg. No. 333-339973). | |||
| 4 | .7 | — | 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 Registrant’s Registration Statement on Form S-3, dated November 12, 1999, Reg. No. 333-90147). | |||
| 10 | .1 | — | 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 Registrant’s 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 Registrant’s Annual Report on Form 10-K for year ended December 31, 2007, SEC File No. 001-4300). | |||
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| 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 Registrant’s 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 Société Générale, as U.S. Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.01 to Registrant’s 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 10.02 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300). | |||
| 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 10.03 to Registrant’s 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 Registrant’s 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 Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, SEC File No. 001-4300). | |||
| †10 | .9 | — | Apache Corporation Corporate Incentive Compensation Plan A (Senior Officers’ Plan), dated July 16, 1998 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300). | |||
| Apache Corporation Corporate Incentive Compensation Plan A (Senior Officers’ Plan), dated July 16, 1998 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300). | ||||||
| †10 | .10 | — | 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 Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
| †10 | .11 | — | Apache Corporation Corporate Incentive Compensation Plan B (Strategic Objectives Format), dated July 16, 1998 (incorporated by reference to Exhibit 10.14 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300). | |||
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| †10 | .12 | — | 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 Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
| †10 | .13 | — | Apache Corporation 401(k) Savings Plan, dated January 1, 2008 (incorporated by reference to Exhibit 10.20 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
| †10 | .14 | — | Amendment to Apache Corporation 401(k) Savings Plan, dated January 29, 2009, effective as of January 1, 2009, except as otherwise specified (incorporated by reference to Exhibit 10.21 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
| *†10 | .15 | — | Amendment to Apache Corporation 401(k) Savings Plan, dated December 22, 2009, effective as of January 1, 2009, except as otherwise specified. | |||
| *†10 | .16 | — | Non-Qualified Retirement/Savings Plan of Apache Corporation, amended and restated as of February 11, 2010. | |||
| *†10 | .17 | — | Apache Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated effective as of December 31, 2009. | |||
| †10 | .18 | — | Apache Corporation 1998 Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300). | |||
| †10 | .19 | — | Apache Corporation 2000 Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.4 to Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.35 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
| †10 | .26 | — | Apache Corporation Deferred Delivery Plan, as amended and restated November 19, 2008, effective as of January 1, 2009, except as otherwise specified (incorporated by reference to Exhibit 10.36 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, 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 Registrant’s 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 November 20, 2008, effective as of January 1, 2009 (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
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| †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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300). | |||
| †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 Registrant’s 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 Registrant’s 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 Registrant’s 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. | |||
| *†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. | |||
| *†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. | |||
| *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 (incorporated by reference to Exhibit 14.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300). | |||
| *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 | |||
| *99 | .1 | — | Report of Ryder Scott Company L.P., Petroleum Consultants | |||
| **101 | — | The following materials from the Apache Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009, 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. | ||||
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| * | 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 Registrant’s
consolidated assets have been omitted and will be provided to
the Commission upon request.
TABLE OF CONTENTS
Part IprintItem 1A. Risk FactorsprintItem 1B. Unresolved Sec Staff CommentsprintItem 3. Legal ProceedingsprintItem 4. Submission Of Matters To A Vote Of Security HoldersprintPart IIprintItem 5. Market For The Registrant S Common Equity and Related Stockholder MattersprintItem 6. Selected Financial DataprintItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsprintItem 7A. Quantitative and Qualitative Disclosures About Market RiskprintItem 8. Financial Statements and Supplementary DataprintItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureprintItem 9A. Controls and ProceduresprintItem 9B. Other InformationprintPart IIIprintItem 10. Directors and Executive Officers Of The RegistrantprintItem 11. Executive CompensationprintItem 12. Security Ownership Of Certain Beneficial Owners and ManagementprintItem 13. Certain Relationships and Related Transactions, and Director IndependenceprintItem 14. Principal Accountant Fees and ServicesprintPart IVprintItem 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-kprint