2012 Annual Report
Contents
2 Letter to Stockholders
8 Glossary of Energy and Financial Terms
85 Chevron History
4 Chevron Financial Highlights
9 Financial Review
5 Chevron Operating Highlights
69 Five-Year Financial Summary
86 Board of Directors
87 Corporate Officers
6 Chevron at a Glance
70 Five-Year Operating Summary
88 Stockholder and Investor Information
2012 was a year of many milestones. We advanced our major
capital projects and remained on track to meet our production
goal of 3.3 million barrels per day by 2017. We also continued to
add opportunities to our portfolio that we anticipate will position
us for growth well into the next decade. The world needs reliable
and affordable energy. The long-term investments we are making
will help contribute to energy supplies, while creating sustained
value for our stockholders, employees, business partners and
the communities where we operate.
The online version of this report contains additional information
about our company, as well as videos of our various projects. We
invite you to visit our website at: Chevron.com/AnnualReport2012.
Chevron Corporation 2012 Annual Report 1
On the cover: The Second Generation Plant at the Tengiz Field in Kazakhstan is the largest single-train sour crude processing facility in the world. The Tengiz Field, which is operated by our 50 percent-owned affiliate Tengizchevroil, is one of the world’s deepest developed supergiant oil fields.This page: We see growth opportunities in natural gas from shale and have built an extensive portfolio in some of the world’s most promising areas. Here a well is drilled on our acreage in Pennsylvania’s Marcellus Shale. To Our Stockholders
For Chevron, 2012 was another year of delivering strong results. Even as global economic
challenges persisted, we continued building the foundation for sustained growth in our
upstream and downstream businesses. And we produced excellent returns for our stockholders.
Our strong financial performance
was reflected in net income of $26.2
billion on sales and other operating
revenues of $231 billion. We achieved
a competitive 18.7 percent return on
capital employed. We increased our
dividend payout to stockholders for
the 25th consecutive year, marking an
average dividend increase of 1 1 percent
compounded since 2004 — compared
with the average 3 percent of S&P
100 companies over that same period.
Our total stockholder returns of 6.5
percent and 16.3 percent over the past
five- and 10-year periods, respectively,
continue to lead our peer group.
Our major businesses generated strong
operating results. In the upstream,
we ranked No. 1 in earnings per barrel
relative to our peers for the third
straight year. In 2012, we advanced
four deepwater major capital projects
through startup: Usan, Caesar/Tonga,
Agbami 2 and Tahiti 2 — with Tahiti
setting several industry records for
water injection in deepwater production.
Over the next five years, we anticipate
16 project startups with a Chevron
share of investment greater than
$1 billion each. Among them are two
of our three new liquefied natural gas
projects: Angola and Gorgon, offshore
Western Australia; our deepwater
projects Jack/St. Malo, Big Foot and
Tubular Bells in the U.S. Gulf of Mexico;
and the Escravos Gas-to-Liquids
Project in Nigeria.
Exploration successes continued in
2012 with discoveries in seven
countries. That includes Australia’s
Carnarvon Basin, bringing total
discoveries there to 19 since mid-
2009 and positioning our Gorgon
and Wheatstone projects for potential
future expansions. Exploration success
was nearly 74 percent, exceeding our
10-year average of 54 percent. We
added 1.1 billion barrels of net oil-
equivalent proved reserves, replacing
112 percent of production in 2012.
The global restructuring of our
downstream and chemicals business
has delivered greater value from a more
focused footprint. In 2012, we ranked
No. 2 in earnings per barrel relative
We work toward building sustainable
economies by employing people
from our host communities, training
workers to world-class standards,
building capacity and supporting small
business. In 2012, we bought $60 billion
in goods and services around the globe,
providing a meaningful stimulus for
local economies. And in the past seven
years, we invested more than $1 billion
worldwide in programs focused on
economic development, health and
education. You can find more detail
about our social investments in our
companion publication, the 2012
Corporate Responsibility Report.
Our commitment above all is to safely
develop the affordable energy vital
to economic growth. In fulfilling that
commitment, we are mindful of our
unique responsibility as an ambassador
for a system of values — The Chevron
Way — that promotes responsible and
ethical behavior in all we do. We have
the right people with the right skills, an
unparalleled project portfolio, proven
strategies and a culture committed to
being the global energy company most
admired for its people, partnership
and performance. We are strongly
positioned to create enduring value for
the communities where we operate and
for those who place their trust in us —
our stockholders.
Thank you for investing in Chevron.
to our peer group. Construction of a
lubricants facility at our Pascagoula,
Mississippi, refinery is progressing
toward completion by year-end 2013
and is expected to make Chevron the
world’s largest producer of premium
base oil. We are on track to capture
$1 billion in annual refinery profit
improvements, compared with 2008,
through measures including improved
product yields and energy efficiency.
Pennsylvania, water recycling
technology has reduced our fresh
water consumption. To further reduce
our operating footprint, temporary
modular tanks are being tested for
onsite water storage. At our St. Malo
well, a series of field trials points to
the promise of a new system designed
to boost well completion efficiency,
thus reducing rig time, costs and
operational risk.
Our 2013 capital and exploratory
budget of $36.7 billion, combined
with our strong financial position,
supports our long-term growth
strategy. This record level of capital
spending reflects our unmatched
Fundamental to everything we do
is a constant focus on achieving
increasingly higher levels of safety,
operational and environmental
performance. Our efforts are guided
by our Operational Excellence
Our 2013 capital and exploratory budget of $36.7 billion,
combined with our strong financial position, supports our
long-term growth strategy [and] reflects our unmatched
project queue [and] confidence in our competitive advantages.
Management System, which aligns
with international standards for safety
and environmental performance. In
2012, we continued to be an industry
leader in personal safety, as measured
by injuries requiring time away from
work. We also delivered our lowest
spill volumes in a decade. But we are
not incident-free. Our strong safety
culture and our focused efforts in
improving process safety will help
us continually progress toward our
goal of incident-free operations.
project queue, as well as confidence
in our competitive advantages and
organizational capability. It keeps us on
target to reach our production goal of
3.3 million barrels of oil-equivalent per
day by 2017, an increase of more than
20 percent from 2010 levels.
To continually improve our operations,
we develop technologies that advance
our business and create new value.
These include technologies in areas
such as seismic imaging, deepwater
operations and hydrocarbons from
shale that enable us to access new
resources while also ensuring safe
and responsible production. At the
Marcellus Shale operations in western
We apply the same type of commit-
ment to our social performance,
contributing to the creation of stronger
communities wherever we operate.
John S. Watson
Chairman of the Board and
Chief Executive Officer
February 22, 2013
Chevron Corporation 2012 Annual Report 3
CYAN
MAGENTA
YELLOW
BLACK
PMS 425
PMS 2935
PMS 7499
Chevron Financial Highlights
Millions of dollars, except per-share amounts
2012
20 1 1
% Change
Net income attributable to Chevron Corporation
Sales and other operating revenues
Noncontrolling interests income
Interest expense (after tax)
Capital and exploratory expenditures*
Total assets at year-end
Total debt and capital lease obligations at year-end
Noncontrolling interests
Chevron Corporation stockholders’ equity at year-end
Cash provided by operating activities
Common shares outstanding at year-end (Thousands)
Per-share data
Net income attributable to Chevron Corporation — diluted
Cash dividends
Chevron Corporation stockholders’ equity
Common stock price at year-end
Total debt to total debt-plus-equity ratio
Return on average Chevron Corporation stockholders’ equity
Return on capital employed (ROCE)
*Includes equity in affiliates
$ 26,179
$ 230,590
157
$
—
$
$ 34,229
$ 232,982
$ 12,192
$
1,308
$ 136,524
$ 38,812
1,932,530
13.32
$
3.51
$
$
70.65
$ 108.14
$ 26,895
$ 244,371
113
$
—
$
$ 29,066
$ 209,474
$ 10,152
$
799
$ 121,382
$ 41,098
1,966,999
13.44
$
3.09
$
$
61.71
$ 106.40
(2.7) %
(5.6) %
38.9 %
0.0 %
17.8 %
11.2 %
20.1 %
63.7 %
12.5 %
(5.6) %
(1.8) %
(0.9) %
13.6 %
14.5 %
1.6 %
8.2%
20.3%
18.7%
7.7%
23.8%
21.6%
Net Income Attributable
to Chevron Corporation
Billions of dollars
Annual Cash Dividends
Dollars per share
Chevron Year-End
Common Stock Price
Dollars per share
Return on Capital Employed
Percent
30.0
25.0
20.0
15.0
10.0
5.0
0.0
$26.2
3.75
3.00
2.25
1.50
0.75
0.00
$3.51
125
100
75
50
25
0
$108.14
18.7
30
24
18
12
6
0
08
09
10 11 12
08
09
10 11 12
08
09
10 11 12
08
09
10 11 12
The decrease in 2012 was due to
lower earnings in upstream as a
result of lower crude oil production
volume.
The company’s annual dividend
increased for the 25th consecutive
year.
The company’s stock price rose
1.6 percent in 2012.
Chevron’s return on capital
employed declined to 18.7 percent
on lower earnings and higher
capital employed.
4 Chevron Corporation 2012 Annual Report
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#002 – Net Income – v1
#004 – Cash Dividends – v1
#008 – Year End Common Stock – v1
#006 – Return on Avg. Cap. – v1
3/8/13 3:14 PM
Artwork Released to ColorGraphics 02XX13 Text Updated: 02 1 41 3
Chevron Operating Highlights1
2012
20 1 1
% Change
Net production of crude oil, condensate and natural gas liquids (Thousands of barrels per day)
Net production of natural gas (Millions of cubic feet per day)
Total net oil-equivalent production (Thousands of oil-equivalent barrels per day)
Refinery input (Thousands of barrels per day)
Sales of refined products (Thousands of barrels per day)
Net proved reserves of crude oil, condensate and natural gas liquids2 (Millions of barrels)
— Consolidated companies
— Affiliated companies
Net proved reserves of natural gas2 (Billions of cubic feet)
1,764
5,074
2,610
1,702
2,765
4,353
2,128
— Consolidated companies
— Affiliated companies
Net proved oil-equivalent reserves2 (Millions of barrels)
— Consolidated companies
— Affiliated companies
Number of employees at year-end3
1 Includes equity in affiliates, except number of employees
2 At the end of the year
3 Excludes service station personnel
25,654
3,541
8,629
2,718
58,286
1,849
4,941
2,673
1,787
2,949
4,295
2,160
25,229
3,454
8,500
2,736
57,376
(4.6) %
2.7 %
(2.4) %
(4.8) %
(6.2) %
1.4 %
(1.5) %
1.7 %
2.5 %
1.5 %
(0.7) %
1.6 %
Performance Graph
Five-Year Cumulative Total Returns
(Calendar years ended December 31)
The stock performance graph at right shows how
an initial investment of $100 in Chevron stock
would have compared with an equal investment in
the S&P 500 Index or the Competitor Peer Group.
The comparison covers a five-year period begin ning
December 31, 2007, and ending December 31, 2012,
and for the peer group is weighted by market capital-
ization as of the beginning of each year. It includes
the reinvestment of all dividends that an investor
would be entitled to receive and is adjusted for stock
splits. The interim measurement points show the
value of $100 invested on December 31, 2007, as
of the end of each year between 2008 and 2012.
s
r
a
l
l
o
D
140
120
100
80
60
2007
2008
2009
2010
2011
2012
Chevron
S&P 500
Peer Group*
Chevron
S&P 500
Peer Group*
2007
100
100
100
2008
81.64
63.00
75.86
2009
88.25
79.66
80.58
2010
108.45
91.65
81.46
2011
130.43
93.59
93.07
2012
136.95
108.56
96.79
*Peer Group: BP p.l.c.-ADS, ExxonMobil, Royal Dutch Shell p.l.c.-ADS, Total S.A.-ADS
Five-Year Cum. Total Returns – v2
Chevron Corporation 2012 Annual Report 5
CVX_AR2012_v9.2_021413_r1.indd 5
2/22/13 11:18 AM
Photo: Operations Adviser
Kassi Harrington reviews a plan
of the system that provides steam
at the correct pressure, volume and
quality to injection wells at the Kern
River Field steamflood operations
in Bakersfield, California.
6 Chevron Corporation 2012 Annual Report
Chevron at a GlanceChevron is one of the world’s leading integrated energy companies. Our success is driven by our people and their commitment to get results the right way — by operating responsibly, executing with excellence, applying innovative technologies and capturing new opportunities for profitable growth. We are involved in virtually every facet of the energy industry. We explore for, produce and transport crude oil and natural gas; refine, market and distribute transportation fuels and lubricants; manufacture and sell petrochemical products; generate power and produce geothermal energy; provide renewable energy and energy efficiency solutions; and develop the energy resources of the future, including conducting advanced biofuels research. Artwork Released to ColorGraphics 013113 Text Updated: 02 1 41 3
Artwork Released to ColorGraphics 0209 11; Text Updated: 02 1 8 1 1
Upstream
and Gas
Exploration and
Production
Strategy:
Grow profitably in
core areas and build
new legacy positions.
Upstream explores for and produces crude oil and natural gas. At the end of 2012,
worldwide net oil-equivalent proved reserves for consolidated and affiliated companies
were 1 1.35 billion barrels. In 2012, net oil-equivalent production averaged 2.61 million
barrels per day. Major producing areas include Angola, Australia, Azerbaijan, Bangladesh,
Brazil, Canada, China, Denmark, Indonesia, Kazakhstan, Nigeria, the Partitioned Zone
between Kuwait and Saudi Arabia, the Philippines, Thailand, the United Kingdom, the
United States, and Venezuela. Major exploration areas include the U.S. Gulf of Mexico and
the offshore areas of Western Australia and western Africa. Additional areas include the
Gulf of Thailand, the Kurdistan Region of Iraq, the South China Sea, and the offshore areas
of Canada, Liberia, Norway, Sierra Leone, Suriname and the United Kingdom. Shale gas
exploration areas include Argentina, Canada, China, Lithuania, Poland, Romania and the
United States.
Gas and Midstream
Strategy:
Commercialize our equity
gas resource base while
growing a high-impact
global gas business.
We are engaged in every aspect of the natural gas business — liquefaction, pipeline and
marine transport, marketing and trading, and power generation. Overall, we have approxi-
mately 160 trillion cubic feet of natural gas unrisked resources. In North America, Chevron
ranks among the top natural gas marketers with sales in 2012 averaging approximately
6 billion cubic feet per day. We own, operate or have an interest in an extensive network
of crude oil, refined product, chemical, natural gas liquid and natural gas pipelines. Chevron
Shipping Company manages a fleet of four U.S. and 24 international vessels.
Downstream
and Chemicals
Strategy:
Improve returns and
grow earnings across
the value chain.
Downstream and Chemicals includes refining, fuels and lubricants marketing, petro-
chemicals manufacturing and marketing, supply and trading, and transportation. In 2012,
we processed 1.7 million barrels of crude oil per day and averaged 2.8 million barrels per
day of refined product sales worldwide. Our most significant areas of operations are the
west coast of North America, the U.S. Gulf Coast, Singapore, Thailand, South Korea,
Australia and South Africa. We hold interests in 14 fuel refineries and market transportation
fuels and lubricants under the Chevron, Texaco and Caltex brands. Products are sold
through a network of 16,769 retail stations, including those of affiliated companies. Our
chemicals business includes Chevron Phillips Chemical Company LLC, a 50 percent-owned
affiliate that is one of the world’s leading manufacturers of commodity petrochemicals,
and Chevron Oronite Company LLC, which develops, manufactures and markets quality
additives that improve the performance of fuels and lubricants.
Technology
Strategy:
Differentiate performance
through technology.
Our three technology companies — Energy Technology, Technology Ventures and
Information Technology — are focused on driving business value in every aspect of our
operations. We operate technology centers in Australia, the United Kingdom and the
United States. Together they provide strategic research, technology development, and
technical and computing infrastructure services to our global businesses.
Renewable
Energy and
Energy
Efficiency
Operational
Excellence
Strategy:
Invest in profitable
renewable energy
and energy efficiency
solutions.
We are one of the world’s leading producers of geothermal energy, with operations in
Indonesia and the Philippines. We are involved in developing promising renewable sources
of energy, including advanced biofuels from nonfood sources. Our subsidiary Chevron
Energy Solutions works with internal and external clients to develop and build sustainable
energy projects that increase energy efficiency and reduce costs.
The foundation of our business success and world-class performance is operational
excellence, which we define as the systematic management of process safety, personal
safety and health, environment, reliability, and efficiency. Safety is our highest priority.
We are committed to attaining world-class standards in operational excellence. We will
not be satisfied until we have zero incidents.
CVX_AR2012_v9.2_021413_r3.indd 7
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Chevron Corporation 2012 Annual Report 7
Glossary of Energy and Financial Terms
Energy Terms
Additives Specialty chemicals incorporated into fuels
and lubricants that enhance the performance of the
finished products.
Barrels of oil-equivalent (BOE) A unit of measure to
quantify crude oil, natural gas liquids and natural gas
amounts using the same basis. Natural gas volumes
are converted to barrels on the basis of energy
content. See oil-equivalent gas and production.
Biofuel Any fuel that is derived from biomass —
recently living organisms or their metabolic byprod-
ucts — from sources such as farming, forestry, and
biodegradable industrial and municipal waste.
See renewables.
Condensate Hydrocarbons that are in a gaseous
state at reservoir conditions but condense into liquid
as they travel up the wellbore and reach surface
conditions.
Development Drilling, construction and related
activities following discovery that are necessary to
begin production and transportation of crude oil
and natural gas.
Enhanced recovery Techniques used to increase
or prolong production from crude oil and natural
gas fields.
Exploration Searching for crude oil and/or natural
gas by utilizing geologic and topographical studies,
geophysical and seismic surveys, and drilling of wells.
Gas-to-liquids (GTL) A process that converts natural
gas into high-quality transportation fuels and other
products.
Greenhouse gases Gases that trap heat in Earth’s
atmosphere (e.g., water vapor, ozone, carbon dioxide,
methane, nitrous oxide, hydrofluorocarbons, perfluor-
ocarbons and sulfur hexafluoride).
Integrated energy company A company engaged in
all aspects of the energy industry, including exploring
for and producing crude oil and natural gas; refining,
marketing and transporting crude oil, natural gas and
refined products; manufacturing and distributing
petrochemicals; and generating power.
Liquefied natural gas (LNG) Natural gas that
is liquefied under extremely cold temperatures
to facilitate storage or transportation in specially
designed vessels.
Natural gas liquids (NGLs) Separated from natural
gas, these include ethane, propane, butane and
natural gasoline.
Oil-equivalent gas (OEG) The volume of natural gas
needed to generate the equivalent amount of heat as
a barrel of crude oil. Approximately 6,000 cubic feet
of natural gas is equivalent to one barrel of crude oil.
Oil sands Naturally occurring mixture of bitumen
(a heavy, viscous form of crude oil), water, sand and
clay. Using hydroprocessing technology, bitumen can
be refined to yield synthetic oil.
Petrochemicals Compounds derived from petro-
leum. These include aromatics, which are used to
make plastics, adhesives, synthetic fibers and
household detergents; and olefins, which are used
to make packaging, plastic pipes, tires, batteries,
household detergents and synthetic motor oils.
8 Chevron Corporation 2012 Annual Report
Price effects on entitlement volumes The impact
on Chevron’s share of net production and net proved
reserves due to changes in crude oil and natural gas
prices between periods. Under production-sharing
and variable-royalty provisions of certain agree-
ments, price variability can increase or decrease
royalty burdens and/or volumes attributable to
the company. For example, at higher prices, fewer
volumes are required for Chevron to recover its
costs under certain production-sharing contracts.
Production Total production refers to all the crude
oil (including synthetic oil), natural gas liquids and
natural gas produced from a property. Net produc-
tion is the company’s share of total production
after deducting both royalties paid to landowners
and a government’s agreed-upon share of produc-
tion under a production-sharing contract. Liquids
production refers to crude oil, condensate, natural
gas liquids and synthetic oil volumes. Oil-equivalent
production is the sum of the barrels of liquids and the
oil-equivalent barrels of natural gas produced. See
barrels of oil-equivalent and oil-equivalent gas.
Production-sharing contract (PSC) An agreement
between a government and a contractor (generally
an oil and gas company) whereby production is
shared between the parties in a prearranged manner.
The contractor typically incurs all exploration, devel-
opment and production costs, which are subsequently
recoverable out of an agreed-upon share of any
future PSC production, referred to as cost recovery
oil and/or gas. Any remaining production, referred
to as profit oil and/or gas, is shared between the
parties on an agreed-upon basis as stipulated in the
PSC. The government also may retain a share of PSC
production as a royalty payment, and the contractor
typically owes income tax on its portion of the profit
oil and/or gas. The contractor’s share of PSC oil and/
or gas production and reserves varies over time as it
is dependent on prices, costs and specific PSC terms.
Renewables Energy resources that are not depleted
when consumed or converted into other forms of
energy (e.g., solar, geothermal, ocean and tide,
wind, hydroelectric power, biofuels and hydrogen).
Reserves Crude oil and natural gas contained in
underground rock formations called reservoirs
and saleable hydrocarbons extracted from oil sands,
shale, coalbeds and other nonrenewable natural
resources that are intended to be upgraded into
synthetic oil or gas. Net proved reserves are the
estimated quantities that geoscience and engineer-
ing data demonstrate with reasonable certainty to
be economically producible in the future from known
reservoirs under existing economic conditions,
operating methods and government regulations, and
exclude royalties and interests owned by others.
Estimates change as additional information becomes
available. Oil-equivalent reserves are the sum of the
liquids reserves and the oil-equivalent gas reserves.
See barrels of oil-equivalent and oil-equivalent gas.
The company discloses only net proved reserves
in its filings with the U.S. Securities and Exchange
Commission. Investors should refer to proved
reserves disclosures in Chevron’s Annual Report on
Form 10-K for the year ended December 31, 2012.
Resources Estimated quantities of oil and gas
resources are recorded under Chevron’s 6P system,
which is modeled after the Society of Petroleum
Engineers’ Petroleum Resource Management System,
and includes quantities classified as proved, probable
and possible reserves, plus those that remain
contingent on commerciality. Unrisked resources,
unrisked resource base and similar terms represent
the arithmetic sum of the amounts recorded under
each of these classifications. Recoverable resources,
potentially recoverable volumes and other similar
terms represent estimated remaining quantities that
are expected to be ultimately recoverable and pro-
duced in the future, adjusted to reflect the relative
uncertainty represented by the various classifica-
tions. These estimates may change significantly as
development work provides additional information.
At times, original oil in place and similar terms are
used to describe total hydrocarbons contained in a
reservoir without regard to the likelihood of their
being produced. All of these measures are considered
by management in making capital investment and
operating decisions and may provide some indication
to stockholders of the resource potential of oil and gas
properties in which the company has an interest.
Shale gas Natural gas produced from shale (very
fine-grained rock) formations where the gas was
sourced from within the shale itself and is trapped
in rocks with low porosity and extremely low per-
meability. Production of shale gas requires the use
of hydraulic fracturing (pumping a fluid-sand mixture
into the formation under high pressure) to help
produce the gas.
Synthetic oil A marketable and transportable hydro-
carbon liquid, resembling crude oil, that is produced
by upgrading highly viscous or solid hydrocarbons,
such as extra-heavy crude oil or oil sands.
Financial Terms
Cash flow from operating activities Cash generated
from the company’s businesses; an indicator of a
company’s ability to pay dividends and fund capital
and common stock repurchase programs. Excludes
cash flows related to the company’s financing and
investing activities.
Earnings Net income attributable to Chevron
Corporation as presented on the Consolidated
Statement of Income.
Margin The difference between the cost of purchas-
ing, producing and/or marketing a product and its
sales price.
Return on capital employed (ROCE) Ratio calculated
by dividing earnings (adjusted for after-tax interest
expense and noncontrolling interests) by the average
of total debt, noncontrolling interests and Chevron
Corporation stockholders’ equity for the year.
Return on stockholders’ equity Ratio calculated
by dividing earnings by average Chevron Corporation
stockholders’ equity. Average Chevron Corporation
stockholders’ equity is computed by averaging
the sum of the beginning-of-year and end-of-year
balances.
Total stockholder return (TSR) The return to stock-
holders as measured by stock price appreciation and
reinvested dividends for a period of time.
CVX_AR2012_v9.2_021413_r1.indd 8
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Financial Table of Contents
10
36
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Key Financial Results 10
Earnings by Major Operating Area 10
Business Environment and Outlook 10
Operating Developments 13
Results of Operations 14
Consolidated Statement of Income 17
Selected Operating Data 18
Liquidity and Capital Resources 19
Financial Ratios 21
Guarantees, Off-Balance-Sheet Arrangements and Contractual
Obligations, and Other Contingencies 21
Financial and Derivative Instruments 22
Transactions With Related Parties 23
Litigation and Other Contingencies 23
Environmental Matters 23
Critical Accounting Estimates and Assumptions 24
New Accounting Standards 27
Quarterly Results and Stock Market Data 28
29
Consolidated Financial Statements
Report of Management 29
Report of Independent Registered Public Accounting Firm 30
Consolidated Statement of Income 31
Consolidated Statement of Comprehensive Income 32
Consolidated Balance Sheet 33
Consolidated Statement of Cash Flows 34
Consolidated Statement of Equity 35
Notes to the Consolidated Financial Statements
Note 1
Note 2 Noncontrolling Interests 38
Note 3
Information Relating to the Consolidated
Summary of Significant Accounting Policies 36
Statement of Cash Flows 39
Note 4
Note 5
Summarized Financial Data – Chevron U.S.A. Inc. 40
Summarized Financial Data –
Chevron Transport Corporation Ltd. 40
Investments and Advances 46
Summarized Financial Data – Tengizchevroil LLP 41
Lease Commitments 41
Fair Value Measurements 41
Financial and Derivative Instruments 43
Note 6
Note 7
Note 8
Note 9
Note 10 Operating Segments and Geographic Data 44
Note 11
Note 12 Properties, Plant and Equipment 48
Note 13 Litigation 48
Note 14 Taxes 51
Note 15 Short-Term Debt 54
Note 16 Long-Term Debt 54
Note 17 New Accounting Standards 55
Note 18 Accounting for Suspended Exploratory Wells 55
Note 19 Stock Options and Other Share-Based Compensation 56
Note 20 Employee Benefit Plans 57
Note 21 Equity 63
Note 22 Other Contingencies and Commitments 63
Note 23 Asset Retirement Obligations 66
Note 24 Other Financial Information 66
Note 25 Earnings Per Share 67
Note 26 Acquisition of Atlas Energy, Inc. 68
Five-Year Financial Summary 69
Five-Year Operating Summary 70
Supplemental Information on Oil and Gas Producing Activities 71
Cautionary Statement Relevant to Forward-Looking Information
for the Purpose of “Safe Harbor” Provisions of the Private Securities
Litigation Reform Act of 1995
This Annual Report of Chevron Corporation contains forward-looking state-
ments relating to Chevron’s operations that are based on management’s
current expectations, estimates and projections about the petroleum,
chemicals and other energy-related industries. Words such as “anticipates,”
“expects,” “intends,” “plans,” “targets,” “forecasts,” “projects,” “believes,”
“seeks,” “schedules,” “estimates,” “budgets,” “outlook” and similar expressions
are intended to identify such forward-looking statements. These statements are
not guarantees of future performance and are subject to certain risks, uncer-
tainties and other factors, many of which are beyond the company’s control
and are difficult to predict. Therefore, actual outcomes and results may
differ materially from what is expressed or forecasted in such forward-looking
statements. The reader should not place undue reliance on these forward-
looking statements, which speak only as of the date of this report. Unless
legally required, Chevron undertakes no obligation to update publicly any
forward-looking statements, whether as a result of new information, future
events or otherwise.
Among the important factors that could cause actual results to differ
materially from those in the forward-looking statements are: changing crude
oil and natural gas prices; changing refining, marketing and chemical margins;
actions of competitors or regulators; timing of exploration expenses; timing of
crude oil liftings; the competitiveness of alternate-energy sources or product
substitutes; technological developments; the results of operations and financial
condition of equity affiliates; the inability or failure of the company’s joint-
venture partners to fund their share of operations and development activities;
the potential failure to achieve expected net production from existing
and future crude oil and natural gas development projects; potential delays
in the development, construction or start-up of planned projects; the potential
disruption or interruption of the company’s production or manufacturing facil-
ities or delivery/transportation networks due to war, accidents, political events,
civil unrest, severe weather or crude oil production quotas that might be
imposed by the Organization of Petroleum Exporting Countries; the potential
liability for remedial actions or assessments under existing or future environ-
mental regulations and litigation; significant investment or product changes
required by existing or future environmental statutes, regulations and
litigation; the potential liability resulting from other pending or future
litigation; the company’s future acquisition or disposition of assets and gains
and losses from asset dispositions or impairments; government-mandated
sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal
terms or restrictions on scope of company operations; foreign currency
movements compared with the U.S. dollar; the effects of changed accounting
rules under generally accepted accounting principles promulgated by rule-
setting bodies. In addition, such results could be affected by general domestic
and international economic and political conditions. Other unpredictable or
unknown factors not discussed in this report could also have material adverse
effects on forward-looking statements.
Chevron Corporation 2012 Annual Report 9
Management’s Discussion and Analysis of
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Results of Operations
Key Financial Results
Millions of dollars, except per-share amounts
2012
2011
2010
Net Income Attributable to
Chevron Corporation
Per Share Amounts:
Net Income Attributable to
Chevron Corporation
– Basic
– Diluted
Dividends
Sales and Other
Operating Revenues
Return on:
Capital Employed
Stockholders’ Equity
$ 26,179
$ 26,895
$ 19,024
$ 13.42
$ 13.32
3.51
$
$ 13.54
$ 13.44
3.09
$
$
$
$
9.53
9.48
2.84
$ 230,590
$ 244,371
$ 198,198
18.7%
20.3%
21.6%
23.8%
17.4%
19.3%
Earnings by Major Operating Area
Millions of dollars
2012
2011
2010
Upstream
United States
International
Total Upstream
Downstream
United States
International
Total Downstream
All Other
Net Income Attributable to
Chevron Corporation1,2
$ 5,332
18,456
23,788
$ 6,512
18,274
24,786
$
4,122
13,555
17,677
2,048
2,251
4,299
(1,908)
1,506
2,085
3,591
(1,482)
1,339
1,139
2,478
(1,131)
$ 26,179
$ 26,895
$ 19,024
1 Includes foreign currency effects:
2 Also referred to as “earnings” in the discussions that follow.
$ (454)
$ 121
$ (423)
Refer to the “Results of Operations” section beginning
on page 14 for a discussion of financial results by major
operating area for the three years ended December 31, 2012.
Business Environment and Outlook
Chevron is a global energy company with substantial busi-
ness activities in the following countries: Angola, Argentina,
Australia, Azerbaijan, Bangladesh, Brazil, Cambodia,
Canada, Chad, China, Colombia, Democratic Republic of
the Congo, Denmark, Indonesia, Kazakhstan, Myanmar, the
Netherlands, Nigeria, Norway, the Partitioned Zone between
Saudi Arabia and Kuwait, the Philippines, Republic of the
Congo, Singapore, South Africa, South Korea, Thailand,
Trinidad and Tobago, the United Kingdom, the United
States, Venezuela, and Vietnam.
Earnings of the company depend mostly on the profit-
ability of its upstream and downstream business segments.
The biggest factor affecting the results of operations for the
company is the level of the price of crude oil. In the down-
stream business, crude oil is the largest cost component
of refined products. Seasonality is not a primary driver of
changes in the company’s quarterly earnings during the year.
10 Chevron Corporation 2012 Annual Report
To sustain its long-term competitive position in the
upstream business, the company must develop and replenish
an inventory of projects that offer attractive financial returns
for the investment required. Identifying promising areas for
exploration, acquiring the necessary rights to explore for and
to produce crude oil and natural gas, drilling successfully,
and handling the many technical and operational details in
a safe and cost-effective manner are all important factors in
this effort. Projects often require long lead times and large
capital commitments.
The company’s operations, especially upstream, can also
be affected by changing economic, regulatory and political
environments in the various countries in which it operates,
including the United States. From time to time, certain
governments have sought to renegotiate contracts or impose
additional costs on the company. Governments may attempt
to do so in the future. Civil unrest, acts of violence or
strained relations between a government and the company or
other governments may impact the company’s operations or
investments. Those developments have at times significantly
affected the company’s operations and results and are care-
fully considered by management when evaluating the level of
current and future activity in such countries.
The company continually evaluates opportunities to
dispose of assets that are not expected to provide sufficient
long-term value or to acquire assets or operations comple-
mentary to its asset base to help augment the company’s
financial performance and growth. Refer to the “Results of
Operations” section beginning on page 14 for discussions of
net gains on asset sales during 2012. Asset dispositions and
restructurings may also occur in future periods and could
result in significant gains or losses.
The company closely monitors developments in the
financial and credit markets, the level of worldwide economic
activity, and the implications for the company of movements
in prices for crude oil and natural gas. Management takes
these developments into account in the conduct of daily
operations and for business planning.
Comments related to earnings trends for the company’s
major business areas are as follows:
Upstream Earnings for the upstream segment are
closely aligned with industry price levels for crude oil and
natural gas. Crude oil and natural gas prices are subject to
external factors over which the company has no control,
including product demand connected with global economic
conditions, industry inventory levels, production quotas
imposed by the Organization of Petroleum Exporting Coun-
tries (OPEC), weather-related damage and disruptions,
competing fuel prices, and regional supply interruptions or
fears thereof that may be caused by military conflicts, civil
unrest or political uncertainty. Any of these factors could
Chevron Corporation 2012 Annual Report 11
also inhibit the company’s production capacity in an affected
region. The company closely monitors developments in the
countries in which it operates and holds investments, and
seeks to manage risks in operating its facilities and busi-
nesses. The longer-term trend in earnings for the upstream
segment is also a function of other factors, including the
company’s ability to find or acquire and efficiently produce
crude oil and natural gas, changes in fiscal terms of contracts,
and changes in tax laws and regulations.
The company continues to actively manage its schedule
of work, contracting, procurement and supply-chain activities
to effectively manage costs. However, price levels for capital
and exploratory costs and operating expenses associated with
the production of crude oil and natural gas can be subject
to external factors beyond the company’s control. External
factors include not only the general level of inflation, but
also commodity prices and prices charged by the industry’s
material and service providers, which can be affected by the
volatility of the industry’s own supply-and-demand condi-
tions for such materials and services. Capital and exploratory
expenditures and operating expenses can also be affected by
damage to production facilities caused by severe weather or
civil unrest.
WTI Crude Oil, Brent Crude Oil and Henry Hub Natural Gas Spot Prices —
Quarterly Average
Brent
WTI
HH
WTI/Brent
$/bbl
150
120
90
60
30
0
HH
$/mcf
25
20
15
10
5
0
1Q
2Q
3Q
4Q
1Q
2Q
3Q
4Q
1Q
2Q
3Q
4Q
2010
2011
2012
The chart above shows the trend in benchmark prices
for Brent crude oil, West Texas Intermediate (WTI) crude
oil and U.S. Henry Hub natural gas. The Brent price aver-
aged $112 per barrel for the full-year 2012, compared to
$111 in 2011. As of mid-February 2013, the Brent price was
about $118 per barrel. The majority of the company’s equity
#009 – Crude Oil Prices 2009 through 2011 – v2
crude production is priced based on the Brent benchmark.
The WTI price averaged $94 per barrel for the full-year
2012, compared to $95 in 2011. As of mid-February 2013,
the WTI price was about $97 per barrel. WTI traded at a
discount to Brent throughout 2012 due to high inventories
in the U.S. midcontinent market driven by strong growth in
domestic production.
A differential in crude oil prices exists between high-
quality (high-gravity, low-sulfur) crudes and those of lower
quality (low-gravity, high-sulfur). The amount of the dif-
ferential in any period is associated with the supply of heavy
crude available versus the demand, which is a function of
the capacity of refineries that are able to process this lower
quality feedstock into light products (motor gasoline, jet
fuel, aviation gasoline and diesel fuel). During 2012, the dif-
ferential between U.S. light and heavy crude oil remained
below historical norms as light sweet crude oil production in
the midcontinent region increased and outbound capacity at
Cushing remained constrained. Outside of the U.S., the dif-
ferential narrowed modestly during 2012 as additional heavy
crude oil conversion capacity came on line.
Chevron produces or shares in the production of heavy
crude oil in California, Chad, Indonesia, the Partitioned
Zone between Saudi Arabia and Kuwait, Venezuela and in
certain fields in Angola, China and the United Kingdom
sector of the North Sea. (See page 18 for the company’s
average U.S. and international crude oil realizations.)
In contrast to price movements in the global market
for crude oil, price changes for natural gas in many regional
markets are more closely aligned with supply-and-demand
conditions in those markets. In the United States, prices at
Henry Hub averaged $2.71 per thousand cubic feet (MCF)
during 2012, compared with about $4.00 during 2011. As
of mid-February 2013, the Henry Hub spot price was about
$3.30 per MCF. Fluctuations in the price of natural gas
in the United States are closely associated with customer
demand relative to the volumes produced in North America.
Outside the United States, price changes for natural gas
depend on a wide range of supply, demand and regulatory
circumstances. In some locations, Chevron is investing in
long-term projects to install infrastructure to produce and
liquefy natural gas for transport by tanker to other markets.
International natural gas realizations averaged about $6.00
per MCF during 2012, compared with about $5.40 per MCF
during 2011. (See page 18 for the company’s average natural
gas realizations for the U.S. and international regions.)
Net Liquids Production*
Thousands of barrels per day
Net Natural Gas Production*
Millions of cubic feet per day
5,074
2000
1600
1200
800
400
0
1,764
5500
4400
3300
2200
1100
0
08
09
10 11 12
08
09
10 11 12
United States
International
Net liquids production decreased
5 percent in 2012 mainly due to
field declines in the United States
and international locations, the
shut-in of the Frade Field in Brazil,
and a major planned turnaround at
Tengizchevroil.
United States
International
Net natural gas production increased
3 percent in 2012 mainly due to
increases in Thailand, Bangladesh
and the Marcellus Shale. Partially
offsetting the increases were field
declines in the United States,
Australia and the United Kingdom.
* Includes equity in affiliates.
* Includes equity in affiliates.
10 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 11
#011B – Net Natural Gas Production – v4
#10B – Net Crude Oil & Nat Gas
Liquids Production (back) – v5
Management’s Discussion and Analysis of
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Results of Operations
The company’s worldwide net oil-equivalent production
in 2012 averaged 2.610 million barrels per day. About one-
fifth of the company’s net oil-equivalent production in 2012
occurred in the OPEC-member countries of Angola, Nigeria,
Venezuela and the Partitioned Zone between Saudi Arabia
and Kuwait. OPEC quotas had no effect on the company’s
net crude oil production in 2012 or 2011. At their December
2012 meeting, members of OPEC supported maintaining the
current production quota of 30 million barrels per day, which
has been in effect since December 2008.
The company estimates that oil-equivalent production
in 2013 will average approximately 2.650 million barrels per
day based on an average Brent price of $112 per barrel for
the full-year 2012. This estimate is subject to many factors
and uncertainties, including quotas that may be imposed by
OPEC, price effects on entitlement volumes, changes in fis-
cal terms or restrictions on the scope of company operations,
delays in project startups or ramp-ups, fluctuations in demand
for natural gas in various markets, weather conditions that
may shut in production, civil unrest, changing geopolitics,
delays in completion of maintenance turnarounds, greater-
than-expected declines in production from mature fields,
or other disruptions to operations. The outlook for future
production levels is also affected by the size and number of
economic investment opportunities and, for new, large-scale
projects, the time lag between initial exploration and the
beginning of production. Investments in upstream projects
generally begin well in advance of the start of the associated
crude oil and natural gas production. A significant majority
of Chevron’s upstream investment is made outside the United
States.
Refer to the “Results of Operations” section on pages
14 through 15 for additional discussion of the company’s
upstream business.
Refer to Table V beginning on page 76 for a tabulation of
the company’s proved net oil and gas reserves by geographic
area, at the beginning of 2010 and each year-end from 2010
through 2012, and an accompanying discussion of major
changes to proved reserves by geographic area for the three-
year period ending December 31, 2012.
On November 7, 2011, while drilling a development
well in the deepwater Frade Field about 75 miles offshore
Brazil, an unanticipated pressure spike caused oil to migrate
from the well bore through a series of fissures to the sea floor,
emitting approximately 2,400 barrels of oil. The source of
the seep was substantially contained within four days and
the well was plugged and abandoned. No evidence of any
coastal or wildlife impacts related to this seep has emerged.
On March 14, 2012, the company identified a small, second
seep in a different part of the field. As a precautionary mea-
sure, the company and its partners decided to temporarily
Net Proved Reserves
Billions of BOE*
Net Proved Reserves
Liquids vs. Natural Gas
Billions of BOE
11.3
12.5
10.0
7.5
5.0
2.5
0.0
11.3
12.5
10.0
7.5
5.0
2.5
0.0
08 09 10 11 12
08
09
10 11 12
Natural Gas
Liquids
Reserve replacement rate in 2012
was 112 percent.
United States
Other Americas
Africa
Asia
Australia
Europe
Affiliates
Net proved reserves for
consolidated companies and
affiliated companies increased
1 percent in 2012.
*2012, 2011, 2010 and 2009 include
barrels of oil-equivalent (BOE)
reserves for Canadian synthetic oil.
#014B – Net Proved Reserves Liquids vs. Nat Gas – v2
suspend field production and received approval from Brazil’s
#14A – Net Proved Reserves (front) – v2
National Petroleum Agency (ANP) to do so. Chevron and its
partners are cooperating with the Brazilian authorities. On
July 19, 2012, ANP issued its final investigative report on the
November 2011 incident. A Brazilian federal district prosecu-
tor filed two civil lawsuits seeking $10.7 billion in damages
for each of the two seeps. The company is not aware of any
basis for damages to be awarded in any civil lawsuit. On July
31, 2012, a court presiding over the civil litigation entered a
preliminary injunction barring Chevron from conducting oil
production and transportation activities in Brazil pending
completion of the legal proceedings commenced by the fed-
eral district prosecutor and the ongoing proceedings of ANP
and the Brazilian environment and natural resources regula-
tory agency. On September 28, 2012, the injunction was
modified to clarify that Chevron may continue its contain-
ment and mitigation activities under supervision of ANP. On
appeal, on November 27, 2012, the injunction was revoked
in its entirety. The federal district prosecutor also filed crimi-
nal charges against 11 Chevron employees. Jurisdiction for
all three matters was moved from Campos to a court in Rio
de Janeiro. On February 19, 2013, the court dismissed the
criminal matter, which is subject to appeal by the prosecutor.
Chevron has submitted to ANP a plan for restarting limited
12 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 13
production in the Frade Field. The company’s ultimate expo-
sure related to the incident is not currently determinable, but
could be significant to net income in any one period.
The company entered into a nonbinding financing term
sheet with Petroboscan, a joint stock company owned 39.2
percent by Chevron, which operates the Boscan Field in Ven-
ezuela. When finalized, the financing is expected to occur
in stages over a limited drawdown period and is intended to
support a specific work program to maintain and increase
production to an agreed-upon level. The terms are designed to
support cash needs for ongoing operations and new develop-
ment, as well as distributions to shareholders — including
current outstanding obligations. The loan will be repaid from
future Petroboscan crude sales. Definitive documents are
under negotiation.
Downstream Earnings for the downstream segment are
closely tied to margins on the refining, manufacturing and
marketing of products that include gasoline, diesel, jet fuel,
lubricants, fuel oil, fuel and lubricant additives, and petro-
chemicals. Industry margins are sometimes volatile and can
be affected by the global and regional supply-and-demand bal-
ance for refined products and petrochemicals and by changes
in the price of crude oil, other refinery and petrochemical
feedstocks, and natural gas. Industry margins can also be
influenced by inventory levels, geopolitical events, costs of
materials and services, refinery or chemical plant capacity uti-
lization, maintenance programs, and disruptions at refineries
or chemical plants resulting from unplanned outages due to
severe weather, fires or other operational events.
Other factors affecting profitability for downstream opera-
tions include the reliability and efficiency of the company’s
refining, marketing and petrochemical assets, the effectiveness
of its crude oil and product supply functions, and the volatility
of tanker-charter rates for the company’s shipping operations,
which are driven by the industry’s demand for crude oil and
product tankers. Other factors beyond the company’s control
include the general level of inflation and energy costs to oper-
ate the company’s refining, marketing and petrochemical
assets.
The company’s most significant marketing areas are the
West Coast of North America, the U.S. Gulf Coast, Asia and
southern Africa. Chevron operates or has significant ownership
interests in refineries in each of these areas. The company com-
pleted a multiyear plan in 2012 to streamline the downstream
asset portfolio to concentrate resources and capital on strategic
assets. In third quarter 2012, the company completed the sale of
its Perth Amboy, New Jersey, refinery, which had been operated
as a products terminal in recent years. In 2012, the company
completed the sale of its fuels marketing and aviation businesses
in eight countries in the Caribbean.
Refer to the “Results of Operations” section on pages 15
through 16 for additional discussion of the company’s down-
stream operations.
All Other consists of mining operations, power generation
businesses, worldwide cash management and debt financing
activities, corporate administrative functions, insurance opera-
tions, real estate activities, energy services, alternative fuels, and
technology companies.
Operating Developments
Key operating developments and other events during 2012
and early 2013 included the following:
Upstream
Australia In October 2012, the company acquired addi-
tional interests in the Clio and Acme fields in the Carnarvon
Basin in exchange for Chevron’s interests in the Browse
development. Consolidating interests in the Carnarvon Basin
fits strategically with long-term plans to grow the Wheatstone
area resource base and creates expansion opportunities for the
Wheatstone Project.
In September 2012, the company completed the sale of
an equity interest in the Wheatstone Project to Tokyo Elec-
tric.
During 2012 and early 2013, the company announced
natural gas discoveries at the 47.3 percent-owned and oper-
ated Pontus prospect in Block WA-37-L, the 50 percent-owned
and operated Satyr prospect in Block WA-374-P, the 50 per-
cent-owned and operated Pinhoe prospect in Block
WA-383-P, the 50 percent-owned and operated Arnhem pros-
pect in Block WA-364-P, and the 50 percent-owned and
operated Kentish Knock South prospect in Block WA-365-P.
These discoveries are expected to contribute to potential
expansion opportunities at company-operated LNG facilities.
During 2012, Chevron signed nonbinding Heads of
Agreement with Tohoku Electric and Chubu Electric and
additional binding agreements with Tokyo Electric for LNG
offtake from the Wheatstone Project. To date, more than 80
percent of Chevron’s equity LNG from Wheatstone is cov-
ered under long-term agreements with customers in Asia.
Angola In early 2013, the company announced it plans
to proceed with the development of the Mafumeira Sul Project
located in Block 0.
Angola-Republic of the Congo Joint Development
Area In third quarter 2012, the company reached a final
investment decision on the cross-border development of the
deepwater Lianzi Field.
Bangladesh In July 2012, the company reached a final
investment decision on the Bibiyana Expansion Project.
Canada In February 2013, Chevron acquired a 50
percent-owned and operated interest in the Kitimat LNG
project and proposed Pacific Trail Pipeline, and a 50 percent
nonoperated interest in approximately 644,000 acres in the
Horn River and Liard Basins.
China In 2012, Chevron entered into an agreement to
acquire two exploration blocks in the South China Sea’s Pearl
River Mouth Basin. Government approval is expected in
2013.
12 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 13
Management’s Discussion and Analysis of
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Results of Operations
Kurdistan Region of Iraq In third quarter 2012,
Chevron acquired an 80 percent interest and operatorship in
the Rovi and Sarta blocks.
Lithuania In October 2012, Chevron acquired a 50
percent interest in a company with exploration interests in a
shale gas block.
Morocco In January 2013, the company announced that
it had signed agreements to explore three offshore areas.
Nigeria In February 2012, production commenced at
the deepwater Usan project.
Sierra Leone In September 2012, the company was
awarded a 55 percent interest and operatorship in two deep-
water exploration blocks.
Suriname In November 2012, the company acquired a
50 percent interest in two offshore exploration blocks.
Ukraine In second quarter 2012, the company bid suc-
cessfully for the right to exclusively negotiate a 50 percent
interest and operatorship in a shale gas block.
United Kingdom In July 2012, the company initiated
front-end engineering and design (FEED) for the deepwater
Rosebank project west of the Shetland Islands.
United States In October 2012, the company acquired
additional acreage in New Mexico. A major portion of the
acreage is located in the Delaware Basin, where the company
is already one of the largest leaseholders.
In second quarter 2012, the company successfully bid
for additional shelf and deepwater exploration acreage in the
central Gulf of Mexico. In fourth quarter 2012, the company
submitted high bids for additional deepwater acreage in the
western Gulf of Mexico.
In first quarter 2012, production commenced at the
Caesar/Tonga project in the deepwater Gulf of Mexico.
Downstream
Caribbean During 2012, the company completed the sale of
its fuels marketing and aviation businesses in eight countries
in the Caribbean.
Europe During first quarter 2012, the company com-
pleted the sale of its fuels marketing, finished lubricants and
aviation businesses in Spain.
Saudi Arabia In October 2012, the company’s 50
percent-owned Chevron Phillips Chemical Company LLC
announced that its 35 percent-owned Saudi Polymers Com-
pany began commercial production at its new petrochemical
facility in Al-Jubail.
South Korea During 2012, the company’s 50 percent-
owned GS Caltex affiliate completed the sale of certain power
and other assets.
United States In third quarter 2012, the company com-
pleted the sale of its idled Perth Amboy, New Jersey, refinery,
which had been operating as a terminal.
In April 2012, the company’s 50 percent-owned Chevron
Phillips Chemical Company LLC announced the execution
of FEED contracts for an ethane cracker at its Cedar Bayou
facility in Baytown, Texas, and two polyethylene facilities
near its Sweeny facility in Old Ocean, Texas.
Other
Common Stock Dividends The quarterly common stock
dividend was increased by 11.1 percent in April 2012 to $0.90
per common share, making 2012 the 25th consecutive year
that the company increased its annual dividend payment.
Common Stock Repurchase Program The company
purchased $5.0 billion of its common stock in 2012 under its
share repurchase program. The program began in 2010 and
has no set term or monetary limits.
Results of Operations
Major Operating Areas The following section presents the
results of operations for the company’s business segments –
Upstream and Downstream – as well as for “All Other.”
Earnings are also presented for the U.S. and international
geographic areas of the Upstream and Downstream business
segments. Refer to Note 10, beginning on page 44, for a
discussion of the company’s “reportable segments,” as defined
in accounting standards for segment reporting (Accounting
Standards Codification (ASC) 280). This section should also
be read in conjunction with the discussion in “Business
Environment and Outlook” on pages 10 through 13.
U.S. Upstream
Millions of dollars
Earnings
2012
2011
2010
$ 5,332
$ 6,512
$ 4,122
U.S. upstream earnings of $5.3 billion in 2012 decreased
$1.2 billion from 2011, primarily due to lower natural gas
and crude oil realizations of $340 million and $200 million,
respectively, lower crude oil production of $240 million, and
lower gains on asset sales of $180 million.
U.S. upstream earnings of $6.5 billion in 2011 increased
$2.4 billion from 2010. The benefit of higher crude oil realiza-
tions increased earnings by $2.8 billion between periods.
Partly offsetting this effect were lower net oil-equivalent pro-
duction, which decreased earnings by about $400 million,
and higher operating expenses of $200 million.
The company’s average realization for U.S. crude oil and
natural gas liquids in 2012 was $95.21 per barrel, compared
with $97.51 in 2011 and $71.59 in 2010. The average natural
gas realization was $2.64 per thousand cubic feet in 2012,
compared with $4.04 and $4.26 in 2011 and 2010,
respectively.
14 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 15
Net oil-equivalent production in 2012 averaged 655,000
barrels per day, down 3 percent from 2011 and 7 percent
from 2010. Between 2012 and 2011, the decrease in produc-
tion was associated with normal field declines and an absence
of volumes associated with Cook Inlet, Alaska, assets sold in
2011. Partially offsetting this decrease was a ramp-up of proj-
ects in the Gulf of Mexico and Marcellus Shale and
improved operational performance in the Gulf of Mexico.
The net liquids component of oil-equivalent production for
2012 averaged 455,000 barrels per day, down 2 percent from
2011 and 7 percent from 2010. Net natural gas production
averaged about 1.2 billion cubic feet per day in 2012, down
approximately 6 percent from 2011 and about 8 percent
from 2010. Refer to the “Selected Operating Data” table on
page 18 for a three-year comparative of production volumes
in the United States.
International Upstream
Millions of dollars
Earnings*
2012
2011
2010
$ 18,456
$ 18,274
$ 13,555
*Includes foreign currency effects:
$ (275)
$ 211
$ (293)
International upstream earnings were $18.5 billion in
2012 compared with $18.3 billion in 2011. The increase was
mainly due to a gain of approximately $1.4 billion on an
asset exchange in Australia, higher natural gas realizations
of about $610 million and a nearly $600 million gain on
sale of an equity interest in the Wheatstone Project. Mostly
offsetting these effects were lower crude oil volumes of about
$1.3 billion and higher exploration expenses of about $430
million. Foreign currency effects decreased earnings by $275
million in 2012, compared with an increase of $211 million a
year earlier.
International upstream earnings of $18.3 billion in 2011
increased $4.7 billion from 2010. Higher prices for crude oil
increased earnings by $7.1 billion. This benefit was partly off-
set by higher tax items of about $1.7 billion and higher
operating expenses, including fuel, of about $1.0 billion. For-
eign currency effects increased earnings by $211 million in
2011, compared with a decrease of $293 million in 2012.
The company’s average realization for international crude
oil and natural gas liquids in 2012 was $101.88 per barrel,
compared with $101.53 in 2011 and $72.68 in 2010. The
average natural gas realization was $5.99 per thousand cubic
feet in 2012, compared with $5.39 and $4.64 in 2011 and
2010, respectively.
International net oil-equivalent production of 1.96 mil-
lion barrels per day in 2012 decreased 2 percent from 2011
and decreased about 5 percent from 2010. New production in
Thailand and Nigeria in 2012 was more than offset by nor-
mal field declines, the shut-in of the Frade field in Brazil and
a major planned turnaround at Tengizchevroil. The decline
between 2011 and 2010 was primarily due to price effects on
entitlement volumes.
The net liquids component of international oil-equivalent
production was about 1.3 million barrels per day in 2012,
a decrease of approximately 5 percent from 2011 and a
Worldwide Upstream Earnings
Billions of dollars
Exploration Expenses
Millions of dollars
$1,728
28.0
21.0
14.0
7.0
0.0
$23.8
2000
1600
1200
800
400
0
08
09
10 11 12
08
09
10 11 12
United States
International
Earnings decreased in 2012 on
lower crude oil volumes.
United States
International
Exploration expenses increased
42 percent from 2011 mainly due
to higher dry hole expense and
geologic and geophysical expense
in the international segment.
decrease of approximately 9 percent from 2010. International
net natural gas production of 3.9 billion cubic feet per day in
2012 was up 6 percent from 2011 and up 4 percent from
#017 – Worldwide Upstream
2010.
Earnings – v2
#016 – Exploration Expenses – v3
Refer to the “Selected Operating Data” table, on page 18,
for a three-year comparative of international production vol-
umes.
U.S. Downstream
Millions of dollars
Earnings
2012
2011
2010
$ 2,048
$ 1,506
$ 1,339
U.S. downstream operations earned $2.0 billion in 2012,
compared with $1.5 billion in 2011. The increase was mainly
due to higher margins on refined product sales of $520 mil-
lion and higher earnings of $140 million from the
50 percent-owned Chevron Phillips Chemical Company LLC
(CPChem). These benefits were partly offset by higher operat-
ing expenses of $130 million.
Earnings of $1.5 billion in 2011 increased $167 mil-
lion from 2010. Earnings benefited by $300 million from
improved margins on refined products, $200 million from
higher earnings from CPChem and $50 million from the
absence of 2010 charges related to employee reductions. These
benefits were partly offset by the absence of a $400 million
gain on the sale of the company’s ownership interest in the
Colonial Pipeline Company recognized in 2010.
Refined product sales of 1.21 million barrels per day in
2012 declined 4 percent, mainly reflecting lower gasoline
and fuel oil sales. Sales volumes of refined products were
1.26 million barrels per day in 2011, a decrease of 7 percent
from 2010. The decline was mainly in gasoline, gas oil and
kerosene sales. U.S. branded gasoline sales of 516,000 barrels
per day in 2012 were essentially flat from 2011 and declined
approximately 10 percent from 2010. The decline in 2012 and
14 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 15
Management’s Discussion and Analysis of
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Results of Operations
2011 from 2010 was primarily due to weaker demand and
previously completed exits from selected eastern U.S. retail
markets.
Refer to the “Selected Operating Data” table on page 18
for a three-year comparison of sales volumes of gasoline and
other refined products and refinery input volumes.
Worldwide Downstream
Earnings*
Billions of dollars
U.S. Gasoline & Other
Refined Product Sales
Thousands of barrels per day
1,211
5.0
3.5
1.5
0.5
(1.0)
$4.3
1600
1200
800
400
0
08
09
10 11 12
08
09
10 11 12
United States
International
Downstream earnings increased
20 percent from 2011 due to higher
margins on the sale of refined
products and higher earnings from
CPChem.
*Includes equity in affiliates.
Gasoline
Jet Fuel
Gas Oils & Kerosene
Residual Fuel Oil
Other
Refined product sales volumes
decreased 4 percent from 2011 on
lower sales of gasoline and lower
sales of residual fuel oil.
International Downstream
Millions of dollars
Earnings*
#019 – WW Downstream
Earnings – v3
*Includes foreign currency effects:
2012
2011
#018 – U.S. Gas & Other Refined
Prod Sales – v3
$ (173)
$ 2,085
$ 2,251
$ 1,139
$ (135)
$ (65)
2010
All Other
derivative instruments of
about $180 million. Foreign
currency effects decreased
earnings by $65 million
in 2011, compared with a
decrease of $135 million in
2010.
Total refined product
International Gasoline &
Other Refined Product
Sales*
Thousands of barrels per day
2250
1800
1,554
0
09
08
450
900
1350
10 11 12
sales of 1.55 million barrels
per day in 2012 declined 8
percent, primarily related to
the third quarter 2011 sale of
the company’s refining and
marketing assets in the
United Kingdom and Ire-
land. Excluding the impact
of 2011 asset sales, sales vol-
umes were flat between the
comparative periods. Interna-
tional refined product sales
volumes of 1.69 million bar-
rels per day in 2011 were 4
percent lower than in 2010,
primarily due to the sale of
the company’s refining and
marketing assets in the
United Kingdom and Ireland. Excluding the impact of 2011
asset sales, sales volumes were up 3 percent between the com-
parative periods.
Sales volumes of refined products
were down 8 percent from 2011
mainly due to the full year impact of
asset sales in the United Kingdom
and Ireland in August 2011.
Gasoline
Jet Fuel
Gas Oils & Kerosene
Residual Fuel Oil
Other
*Includes equity in affiliates.
#020 – Int’l. Gasoline & Other
Refined – v3
Refer to the “Selected Operating Data” table, on page 18,
for a three-year comparison of sales volumes of gasoline and
other refined products and refinery input volumes.
International downstream earned $2.3 billion in 2012,
compared with $2.1 billion in 2011. Earnings increased due
to a favorable change in effects on derivative instruments of
$190 million and higher margins on refined product sales of
$100 million. Foreign currency effects decreased earnings by
$173 million in 2012, compared with a decrease of $65 mil-
lion a year earlier.
Earnings of $2.1 billion in 2011 increased $946 million
from 2010. Gains on asset sales benefited earnings by
$700 million, primarily from the sale of the Pembroke Refin-
ery and related marketing assets in the United Kingdom
and Ireland. Also contributing to earnings were improved
margins of $200 million and the absence of 2010 charges of
$90 million related to employee reductions. These benefits
were partly offset by an unfavorable change in effects on
Millions of dollars
Net charges*
2012
2011
2010
$ (1,908) $ (1,482)
$ (1,131)
*Includes foreign currency effects:
$
(6)
$ (25)
$ 5
All Other includes mining operations, power generation
businesses, worldwide cash management and debt financing
activities, corporate administrative functions, insurance
operations, real estate activities, energy services, alternative
fuels, and technology companies.
Net charges in 2012 increased $426 million from 2011,
mainly due to higher environmental reserve additions, corpo-
rate tax items and other corporate charges, partially offset by
lower employee compensation and benefits expenses.
Net charges in 2011 increased $351 million from 2010,
mainly due to higher expenses for employee compensation
and benefits and higher net corporate tax expenses.
16 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 17
Consolidated Statement of Income
Comparative amounts for certain income statement catego-
ries are shown below:
Millions of dollars
2012
2011
2010
Sales and other operating revenues $ 230,590
$ 244,371 $ 198,198
Sales and other operating revenues decreased in 2012
mainly due to the 2011 sale of the company’s refining and
marketing assets in the United Kingdom and Ireland, and
lower crude oil volumes. Higher 2011 prices for crude oil and
refined products resulted in increased sales and other operat-
ing revenues compared with 2010.
Millions of dollars
2012
2011
2010
Income from equity affiliates
$ 6,889
$ 7,363
$ 5,637
Income from equity affiliates decreased in 2012 from
2011 mainly due to lower upstream-related earnings from
Tengizchevroil in Kazakhstan as a result of lower crude oil
production, and higher operating expenses at Angola LNG
Limited and Petropiar in Venezuela. Downstream-related
earnings were higher between comparative periods, primarily
due to higher margins at CPChem.
Income from equity affiliates increased in 2011 from
2010 mainly due to higher upstream-related earnings from
Tengizchevroil as a result of higher prices for crude oil.
Downstream-related earnings were also higher between the
comparative periods, primarily due to higher earnings from
CPChem as a result of higher margins on sales of commodity
chemicals.
Refer to Note 11, beginning on page 46, for a discussion
of Chevron’s investments in affiliated companies.
Millions of dollars
Other income
2012
2011
2010
$ 4,430
$ 1,972
$ 1,093
Other income of $4.4 billion in 2012 included net gains
from asset sales of approximately $4.2 billion. Other income
in 2011 and 2010 included net gains from asset sales of $1.5
billion and $1.1 billion, respectively. Interest income was
approximately $166 million in 2012, $145 million in 2011
and $120 million in 2010. Foreign currency effects decreased
other income by $207 million in 2012, while increasing other
income by $103 million in 2011 and decreasing other income
by $251 million in 2010.
Millions of dollars
2012
2011
2010
Purchased crude oil and products $ 140,766
$ 149,923
$ 116,467
Crude oil and product purchases of $140.8 billion were
down in 2012 mainly due to the 2011 sale of the company’s
refining and marketing assets in the United Kingdom and
Ireland and lower natural gas prices. Crude oil and prod-
uct purchases in 2011 increased by $33.5 billion from the
prior year due to higher prices for crude oil, natural gas and
refined products.
Millions of dollars
2012
2011
2010
Operating, selling, general and
administrative expenses
$ 27,294
$ 26,394
$ 23,955
Operating, selling, general and administrative expenses
increased $900 million between 2012 and 2011 mainly due
to higher contract labor and professional services of $590
million, and higher employee compensation and benefits of
$280 million.
Operating, selling, general and administrative expenses
increased $2.4 billion between 2011 and 2010. This increase
was primarily related to higher fuel expenses of $1.5 billion
and higher employee compensation and benefits of $700
million. In part, increased fuel purchases in 2011 reflected a
new commercial arrangement that replaced a prior product
exchange agreement for upstream operations in Indonesia.
Millions of dollars
2012
2011
2010
Exploration expense
$ 1,728
$ 1,216
$ 1,147
Exploration expenses in 2012 increased from 2011
mainly due to higher geological and geophysical costs and
well write-offs.
Exploration expenses in 2011 increased from 2010
mainly due to higher geological and geophysical costs, partly
offset by lower well write-offs.
Millions of dollars
2012
2011
2010
Depreciation, depletion and
amortization
$ 13,413
$ 12,911
$ 13,063
The increase in 2012 from 2011 was mainly due to higher
depreciation rates for certain oil and gas producing fields, par-
tially offset by lower production levels. The decrease in 2011
from 2010 mainly reflected lower production levels and the
2011 sale of the Pembroke Refinery, partially offset by higher
depreciation rates for certain oil and gas producing fields.
Millions of dollars
2012
2011
2010
Taxes other than on income
$ 12,376
$ 15,628
$ 18,191
Taxes other than on income decreased in 2012 from 2011
primarily due to lower import duties in the United Kingdom
reflecting the sale of the company’s refining and marketing
assets in the United Kingdom and Ireland in 2011. Partially
offsetting the decrease were excise taxes associated with con-
solidation of Star Petroleum Refining Company beginning
June 2012. Taxes other than on income decreased in 2011
from 2010 primarily due to lower import duties in the United
Kingdom reflecting the 2011 sale of the Pembroke Refinery
and other downstream assets, partly offset by higher excise
taxes in the company’s South Africa downstream operations.
Millions of dollars
Interest and debt expense
2012
$ —
2011
$ —
2010
$ 50
Total interest and debt expenses were fully capitalized in
2012 and 2011.
16 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 17
Management’s Discussion and Analysis of
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Results of Operations
Millions of dollars
2012
2011
2010
Selected Operating Data1,2
Income tax expense
$ 19,996
$ 20,626
$ 12,919
2012
2011
2010
Effective income tax rates were 43 percent in 2012,
43 percent in 2011 and 40 percent in 2010. The rate was
unchanged between 2012 and 2011. The impact of lower
effective tax rates in international upstream operations were
offset by foreign currency remeasurement impacts between
periods. For international upstream, the lower effective tax
rates in the current period were driven primarily by the
effects of asset sales, one-time tax benefits and reduced with-
holding taxes, which were partially offset by a lower
utilization of tax credits during the year. The rate was higher
in 2011 than in 2010 primarily due to higher effective tax
rates in certain international upstream jurisdictions. The
higher international upstream effective tax rates were driven
primarily by lower utilization of non-U.S. tax credits in 2011
and the effect of changes in income tax rates between peri-
ods, which were partially offset by foreign currency
remeasurement impacts.
U.S. Upstream
Net Crude Oil and Natural Gas
455
Liquids Production (MBPD)
Net Natural Gas Production (MMCFPD)3
1,203
Net Oil-Equivalent Production (MBOEPD) 655
5,470
Sales of Natural Gas (MMCFPD)
16
Sales of Natural Gas Liquids (MBPD)
Revenues From Net Production
Liquids ($/Bbl)
Natural Gas ($/MCF)
$ 95.21
$ 2.64
465
1,279
678
5,836
15
489
1,314
708
5,932
22
$ 97.51
$ 4.04
$ 71.59
$ 4.26
International Upstream
Net Crude Oil and Natural Gas
Liquids Production (MBPD)4
Net Natural Gas Production (MMCFPD)3
Net Oil-Equivalent Production
(MBOEPD)4
Sales of Natural Gas (MMCFPD)
Sales of Natural Gas Liquids (MBPD)
Revenues From Liftings
Liquids ($/Bbl)
Natural Gas ($/MCF)
1,309
3,871
1,384
3,662
1,434
3,726
1,955
4,315
24
1,995
4,361
24
2,055
4,493
27
$ 101.88
$ 5.99
$ 101.53
$ 5.39
$ 72.68
$ 4.64
Worldwide Upstream
Net Oil-Equivalent Production
(MBOEPD)4
United States
International
Total
U.S. Downstream
Gasoline Sales (MBPD)5
Other Refined Product Sales (MBPD)
Total Refined Product Sales (MBPD)
Sales of Natural Gas Liquids (MBPD)
Refinery Input (MBPD)
International Downstream
Gasoline Sales (MBPD)5
Other Refined Product Sales (MBPD)
Total Refined Product Sales (MBPD)6
Sales of Natural Gas Liquids (MBPD)
Refinery Input (MBPD)7
655
1,955
2,610
624
587
1,211
141
833
678
1,995
2,673
649
608
1,257
146
854
708
2,055
2,763
700
649
1,349
139
890
412
1,142
1,554
64
869
447
1,245
1,692
63
933
521
1,243
1,764
78
1,004
1 Includes company share of equity affiliates.
2 MBPD – thousands of barrels per day; MMCFPD – millions of cubic feet per day;
MBOEPD – thousands of barrels of oil-equivalents per day; Bbl – Barrel; MCF =
Thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic
feet of natural gas = 1 barrel of oil.
3 Includes natural gas consumed in operations (MMCFPD):
United States
International
4 Includes: Canada – synthetic oil
Venezuela affiliate – synthetic oil
5 Includes branded and unbranded gasoline.
6 Includes sales of affiliates (MBPD):
7 As of June 2012, Star Petroleum Refining Company crude-input volumes are
522
556
63
523
43
17
69
513
40
32
62
475
24
28
562
reported on a 100 percent consolidated basis. Prior to June 2012, crude-input vol-
umes reflect a 64 percent equity interest.
18 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 19
Liquidity and Capital Resources
Cash, cash equivalents, time deposits and marketable
securities Total balances were $21.9 billion and $20.1 bil-
lion at December 31, 2012 and 2011, respectively. Cash
provided by operating activities in 2012 was $38.8 billion,
compared with $41.1 billion in 2011 and $31.4 billion in
2010. Cash provided by operating activities was net of contri-
butions to employee pension plans of approximately
$1.2 billion, $1.5 billion and $1.4 billion in 2012, 2011 and
2010, respectively. Cash provided by investing activities
included proceeds and deposits related to asset sales of
$2.7 billion in 2012, $3.5 billion in 2011, and $2.0 billion in
2010.
Restricted cash of $1.5 billion and $1.2 billion associated
with tax payments, upstream abandonment activities, funds
held in escrow for an asset acquisition and capital investment
projects at December 31, 2012 and 2011, respectively, was
invested in short-term marketable securities and recorded as
“Deferred charges and other assets” on the Consolidated Balance
Sheet.
Dividends Dividends paid to common stockholders
were $6.8 billion in 2012, $6.1 billion in 2011 and $5.7
billion in 2010. In April 2012, the company increased its
quarterly dividend by 11.1 percent to 90 cents per common
share.
Debt and capital lease obligations Total debt and capi-
tal lease obligations were $12.2 billion at December 31, 2012,
up from $10.2 billion at year-end 2011.
The $2.0 billion increase in total debt and capital lease
obligations during 2012 included the net effect of a $4 bil-
lion bond issuance and the early redemption of a $2 billion
bond due in March 2014. The company’s debt and capital
lease obligations due within one year, consisting primarily
of commercial paper, redeemable long-term obligations and
the current portion of long-term debt, totaled $6.0 billion at
December 31, 2012, compared with $5.9 billion at year-end
2011. Of these amounts, $5.9 billion and $5.6 billion were
reclassified to long-term at the end of each period, respec-
tively. At year-end 2012, settlement of these obligations was
not expected to require the use of working capital in 2013, as
the company had the intent and the ability, as evidenced by
committed credit facilities, to refinance them on a long-term
basis.
At December 31, 2012, the company had $6.0 billion in
committed credit facilities with various major banks, expiring
in December 2016, which enable the refinancing of short-
term obligations on a long-term basis. These facilities support
commercial paper borrowing and can also be used for gen-
eral corporate purposes. The company’s practice has been to
continually replace expiring commitments with new com-
mitments on substantially the same terms, maintaining levels
management believes appropriate. Any borrowings under the
facilities would be unsecured indebtedness at interest rates
based on the London Interbank Offered Rate or an average of
base lending rates published by specified banks and on terms
reflecting the company’s strong credit rating. No borrowings
were outstanding under these facilities at December 31, 2012.
In addition, in November 2012, the company filed with the
Securities and Exchange Commission a new registration
statement that expires in November 2015. This registration
statement is for an unspecified amount of nonconvertible
debt securities issued or guaranteed by the company.
The major debt rating agencies routinely evaluate the
company’s debt, and the company’s cost of borrowing can
increase or decrease depending on these debt ratings. The
company has outstanding public bonds issued by Chevron
Corporation, Chevron Corporation Profit Sharing/Sav-
ings Plan Trust Fund and Texaco Capital Inc. All of these
securities are the obligations of, or guaranteed by, Chevron
Corporation and are rated AA by Standard & Poor’s Corpo-
ration and Aa1 by Moody’s Investors Service. The company’s
U.S. commercial paper is rated A-1+ by Standard & Poor’s
and P-l by Moody’s. All of these ratings denote high-quality,
investment-grade securities.
The company’s future debt level is dependent primar-
ily on results of operations, the capital program and cash
that may be generated from asset dispositions. Based on its
high-quality debt ratings, the company believes that it has
substantial borrowing capacity to meet unanticipated cash
requirements. The company also can modify capital spending
plans during any extended periods of low prices for crude oil
and natural gas and narrow margins for refined products and
commodity chemicals to provide flexibility to continue pay-
ing the common stock dividend and maintain the company’s
high-quality debt ratings.
Common stock repurchase program In July 2010, the
Board of Directors approved an ongoing share repurchase
program with no set term or monetary limits. The company
expects to repurchase between $500 million and $2 billion
of its common shares per quarter, at prevailing prices, as
permitted by securities laws and other legal requirements
and subject to market conditions and other factors. During
2012, the company purchased 46.6 million common shares
for $5.0 billion. From the inception of the program through
Cash Provided by
Operating Activities
Billions of dollars
Total Interest Expense &
Total Debt at Year-End
Billions of dollars
45.0
36.0
27.0
18.0
9.0
0.0
$38.8
15.0
12.0
9.0
6.0
3.0
0.0
$12.2
1.5
1.2
0.9
0.6
0.3
0.0
08
09
10 11 12
08
09
10 11 12
Operating cash flows were $2.2
billion lower than 2011, primarily
due to lower benefits from working
capital and lower equity affiliate
distributions.
Total Interest Expense
(right scale)
Total Debt (left scale)
Total debt increased $2.0 billion
during 2012 to $12.2 billion. All
interest expense was capitalized
as part of the cost of major
projects in 2012 and 2011.
Chevron Corporation 2012 Annual Report 19
#022B – Cash Provided by Operating
Activities (back) – v4
#023 – Total Interest Expense and
Total Debt at Year-End – v2
18 Chevron Corporation 2012 Annual Report
Management’s Discussion and Analysis of
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Results of Operations
Capital and Exploratory Expenditures
Millions of dollars
U.S.
Int’l.
2012
Total
U.S.
Int’l.
2011
Total
U.S.
Int’l.
2010
Total
Upstream1
Downstream
All Other
Total
Total, Excluding Equity in Affiliates
1 Excludes the acquisition of Atlas Energy, Inc., in 2011.
1,259
11
$ 8,531 $ 21,913 $ 30,444 $ 8,318 $ 17,554 $ 25,872
3,172 1,461
1,913
2,611
602
583
575
$ 11,046 $ 23,183 $ 34,229 $ 10,354 $ 18,712 $ 29,066
$ 10,738 $ 21,374 $ 32,112 $ 10,077 $ 17,294 $ 27,371
1,150
8
613
$ 3,450 $ 15,454 $ 18,904
2,552
1,096
1,456
299
13
286
$ 5,192 $ 16,563 $ 21,755
$ 4,934 $ 15,433 $ 20,367
spending by affiliates. Approximately 90 percent of the total,
or $33 billion, is budgeted for exploration and production
activities. Approximately $25.5 billion, or 77 percent, of
this amount is for projects outside the United States. Spending
in 2013 is primarily focused on major development projects
in Angola, Australia, Brazil, Canada, China, Kazakhstan,
Nigeria, Republic of Congo, Russia, the United Kingdom
and the U.S. Gulf of Mexico. Also included is funding for
enhancing recovery and mitigating natural field declines for
currently-producing assets, and for focused exploration and
appraisal activities.
Worldwide downstream spending in 2013 is estimated at
$2.7 billion, with about $1.4 billion for projects in the United
States. Major capital outlays include projects under construc-
tion at refineries in the United States, expansion of additives
production capacity in Singapore and chemicals projects in
the United States.
Investments in technology companies, power genera-
tion and other corporate businesses in 2013 are budgeted at
$1 billion.
Noncontrolling interests The company had noncon-
trolling interests of $1,308 million and $799 million at
December 31, 2012 and 2011, respectively. Distributions to
noncontrolling interests totaled $41 million and $71 million
in 2012 and 2011, respectively.
Pension Obligations Information related to pension
plan contributions is included on page 62 in Note 20 to
the Consolidated Financial Statements under the heading
“Cash Contributions and Benefit Payments.” Refer also to
the discussion of pension accounting in “Critical Accounting
Estimates and Assumptions,” beginning on page 24.
2012, the company had purchased 97.7 million shares for
$10.0 billion.
Capital and exploratory expenditures Total expendi-
tures for 2012 were $34.2 billion, including $2.1 billion for the
company’s share of equity-affiliate expenditures. In 2011 and
2010, expenditures were $29.1 billion and $21.8 billion,
respectively, including the company’s share of affiliates’ expen-
ditures of $1.7 billion and $1.4 billion, respectively.
Of the $34.2 billion of expenditures in 2012, 89 percent,
or $30.4 billion, was related to upstream activities. Approxi-
mately 89 percent and 87 percent were expended for
upstream operations in 2011 and 2010. International
upstream accounted for about 72 percent of the worldwide
upstream investment in 2012, about 68 percent in 2011 and
about 82 percent in 2010. These amounts exclude the acquisi-
tion of Atlas Energy, Inc., in 2011.
The company estimates that 2013 capital and exploratory
expenditures will be $36.7 billion, including $3.3 billion of
Upstream —
Capital & Exploratory
Expenditures*
Billions of dollars
Ratio of Total Debt to Total
Debt-Plus-Chevron Corporation
Stockholders’ Equity
Percent
32.0
24.0
16.0
8.0
0.0
$30.4
12.0
8.2%
9.0
6.0
3.0
0.0
08
09
10 11 12
08
09
10 11 12
United States
International
Exploration and production
expenditures were 18 percent
higher than 2011.
* Includes equity in affiliates.
Excludes the acquisition of Atlas
Energy, Inc., in 2011.
The ratio increased to 8.2 percent
at the end of 2012 due to higher
debt, partially offset by an increase
in Stockholders’ Equity.
20 Chevron Corporation 2012 Annual Report
#015 – Exp & Prod – Cap & Exploratory
Expend – v3
#024 – Debt Ratio – v1
Chevron Corporation 2012 Annual Report 21
Financial Ratios
Financial Ratios
Current Ratio
Interest Coverage Ratio
Debt Ratio
2012
1.6
191.3
At December 31
2011
1.6
165.4
2010
1.7
101.7
8.2%
7.7%
9.8%
Current Ratio – current assets divided by current
liabilities, which indicates the company’s ability to repay
its short-term liabilities with short-term assets. The current
ratio in all periods was adversely affected by the fact that
Chevron’s inventories are valued on a last-in, first-out basis.
At year-end 2012, the book value of inventory was lower than
replacement costs, based on average acquisition costs during
the year, by approximately $9.3 billion.
Interest Coverage Ratio – income before income tax
expense, plus interest and debt expense and amortization
of capitalized interest, less net income attributable to non-
controlling interests, divided by before-tax interest costs.
This ratio indicates the company’s ability to pay interest on
outstanding debt. The company’s interest coverage ratio in
2012 was higher than 2011 and 2010 due to lower before-tax
interest costs.
Debt Ratio – total debt as a percentage of total debt
plus Chevron Corporation Stockholders’ Equity, which
indicates the company’s leverage. The increase between
2012 and 2011 was due to higher debt, partially offset by a
higher Chevron Corporation stockholders’ equity balance.
The decrease between 2011 and 2010 was due to a higher
Chevron Corporation stockholders’ equity balance.
Guarantees, Off-Balance-Sheet Arrangements and
Contractual Obligations, and Other Contingencies
Direct Guarantees
Millions of dollars
Guarantee of non-
consolidated affiliate or
joint-venture obligations
Commitment Expiration by Period
Total
2013
2014–
2015
2016–
2017
After
2017
$ 562
$ 38
$ 76
$ 76 $ 372
The company’s guarantee of $562 million is associated
with certain payments under a terminal use agreement
entered into by an equity affiliate. Over the approximate
15-year remaining term of the guarantee, the maximum
guarantee amount will be reduced as certain fees are paid by
the affiliate. There are numerous cross-indemnity agreements
with the affiliate and the other partners to permit recovery
of amounts paid under the guarantee. Chevron has recorded
no liability for its obligation under this guarantee.
Indemnifications Information related to indemnifica-
tions is included on page 64 in Note 22 to the Consolidated
Financial Statements under the heading “Indemnifications.”
Long-Term Unconditional Purchase Obligations and
Commitments, Including Throughput and Take-or-Pay
Agreements The company and its subsidiaries have certain
other contingent liabilities with respect to long-term uncon-
ditional purchase obligations and commitments, including
throughput and take-or-pay agreements, some of which relate
to suppliers’ financing arrangements. The agreements typi-
cally provide goods and services, such as pipeline and storage
capacity, drilling rigs, utilities, and petroleum products, to be
used or sold in the ordinary course of the company’s business.
The aggregate approximate amounts of required payments
under these various commitments are: 2013 – $3.7 billion;
2014 – $3.9 billion; 2015 – $4.1 billion; 2016 – $2.4 billion;
2017 – $1.8 billion; 2018 and after – $6.5 billion. A por-
tion of these commitments may ultimately be shared with
project partners. Total payments under the agreements were
approximately $3.6 billion in 2012, $6.6 billion in 2011 and
$6.5 billion in 2010.
The following table summarizes the company’s signifi-
cant contractual obligations:
Contractual Obligations1
Millions of dollars
On Balance Sheet:2
Short-Term Debt3
Long-Term Debt3
Noncancelable Capital
Lease Obligations
Interest
Off Balance Sheet:
Noncancelable Operating
Payments Due by Period
Total
2013
2014–
2015
2016–
2017
After
2017
127 $
$
11,966
127 $ — $ — $ —
4,043
—
2,000
5,923
189
1,983
45
210
60
408
25
402
59
963
Lease Obligations
3,548
727
1,276
929
616
Throughput and
Take-or-Pay Agreements4 17,164 2,705
5,480
2,904
6,075
Other Unconditional
Purchase Obligations4
5,285 1,003
2,470
1,342
470
1 Excludes contributions for pensions and other postretirement benefit plans.
Information on employee benefit plans is contained in Note 20 beginning on page
57.
2 Does not include amounts related to the company’s income tax liabilities associated with
uncertain tax positions. The company is unable to make reasonable estimates of the peri-
ods in which these liabilities may become payable. The company does not expect
settlement of such liabilities will have a material effect on its consolidated financial posi-
tion or liquidity in any single period.
3 $5.9 billion of short-term debt that the company expects to refinance is included in
long-term debt. The repayment schedule above reflects the projected repayment of the
entire amounts in the 2014–2015 period.
4 Does not include commodity purchase obligations that are not fixed or determinable.
These obligations are generally monetized in a relatively short period of time through
sales transactions or similar agreements with third parties. Examples include obligations
to purchase LNG, regasified natural gas and refinery products at indexed prices.
20 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 21
Management’s Discussion and Analysis of
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Results of Operations
Financial and Derivative Instruments
The market risk associated with the company’s portfolio of
financial and derivative instruments is discussed below. The
estimates of financial exposure to market risk do not rep-
resent the company’s projection of future market changes.
The actual impact of future market changes could differ
materially due to factors discussed elsewhere in this report,
including those set forth under the heading “Risk Factors”
in Part I, Item 1A, of the company’s 2012 Annual Report on
Form 10-K.
Derivative Commodity Instruments Chevron is
exposed to market risks related to the price volatility of crude
oil, refined products, natural gas, natural gas liquids, lique-
fied natural gas and refinery feedstocks.
The company uses derivative commodity instruments to
manage these exposures on a portion of its activity, including
firm commitments and anticipated transactions for the pur-
chase, sale and storage of crude oil, refined products, natural
gas, natural gas liquids and feedstock for company refineries.
The company also uses derivative commodity instruments for
limited trading purposes. The results of these activities were
not material to the company’s financial position, results of
operations or cash flows in 2012.
The company’s market exposure positions are monitored
and managed on a daily basis by an internal Risk Control
group in accordance with the company’s risk management
policies, which have been approved by the Audit Committee
of the company’s Board of Directors.
The derivative commodity instruments used in the
company’s risk management and trading activities consist
mainly of futures, options and swap contracts traded on the
New York Mercantile Exchange and on electronic platforms
of the Inter-Continental Exchange and Chicago Mercantile
Exchange. In addition, crude oil, natural gas and refined
product swap contracts and option contracts are entered into
principally with major financial institutions and other oil and
gas companies in the “over-the-counter” markets.
Derivatives beyond those designated as normal purchase
and normal sale contracts are recorded at fair value on the
Consolidated Balance Sheet in accordance with accounting
standards for derivatives (ASC 815), with resulting gains and
losses reflected in income. Fair values are derived principally
from published market quotes and other independent third-
party quotes. The change in fair value of Chevron’s derivative
commodity instruments in 2012 was a quarterly average
decrease of $31 million in total assets and a quarterly average
increase of $12 million in total liabilities.
The company uses a Value-at-Risk (VaR) model to esti-
mate the potential loss in fair value on a single day from the
effect of adverse changes in market conditions on derivative
commodity instruments held or issued. VaR is the maximum
projected loss not to be exceeded within a given probability
or confidence level over a given period of time. The compa-
ny’s VaR model uses the Monte Carlo simulation method
that involves generating hypothetical scenarios from the
specified probability distributions and constructing a full
distribution of a portfolio’s potential values.
The VaR model utilizes an exponentially weighted
moving average for computing historical volatilities and
correlations, a 95 percent confidence level, and a one-day
holding period. That is, the company’s 95 percent, one-day
VaR corresponds to the unrealized loss in portfolio value that
would not be exceeded on average more than one in every 20
trading days, if the portfolio were held constant for one day.
The one-day holding period is based on the assumption
that market-risk positions can be liquidated or hedged within
one day. For hedging and risk management, the company
uses conventional exchange-traded instruments such as
futures and options as well as non-exchange-traded swaps,
most of which can be liquidated or hedged effectively within
one day. The following table presents the 95 percent/one-day
VaR for each of the company’s primary risk exposures in the
area of derivative commodity instruments at December 31,
2012 and 2011.
Millions of dollars
Crude Oil
Natural Gas
Refined Products
2012
$ 3
3
12
2011
$ 22
4
11
Foreign Currency The company may enter into foreign
currency derivative contracts to manage some of its foreign
currency exposures. These exposures include revenue and
anticipated purchase transactions, including foreign currency
capital expenditures and lease commitments. The foreign cur-
rency derivative contracts, if any, are recorded at fair value on
the balance sheet with resulting gains and losses reflected in
income. There were no open foreign currency derivative con-
tracts at December 31, 2012.
Interest Rates The company may enter into interest rate
swaps from time to time as part of its overall strategy to
manage the interest rate risk on its debt. Interest rate swaps,
if any, are recorded at fair value on the balance sheet with
resulting gains and losses reflected in income. At year-end
2012, the company had no interest rate swaps.
22 Chevron Corporation 2012 Annual Report
Transactions With Related Parties
Chevron enters into a number of business arrangements with
related parties, principally its equity affiliates. These arrange-
ments include long-term supply or offtake agreements and
long-term purchase agreements. Refer to “Other Information”
in Note 11 of the Consolidated Financial Statements, page 47,
for further discussion. Management believes these agreements
have been negotiated on terms consistent with those that
would have been negotiated with an unrelated party.
Litigation and Other Contingencies
MTBE Information related to methyl tertiary butyl ether
(MTBE) matters is included on page 48 in Note 13 to
the Consolidated Financial Statements under the heading
“MTBE.”
Ecuador Information related to Ecuador matters is
included in Note 13 to the Consolidated Financial Statements
under the heading “Ecuador,” beginning on page 48.
Environmental The following table displays the annual
changes to the company’s before-tax environmental
remediation reserves, including those for federal Superfund
sites and analogous sites under state laws.
Millions of dollars
Balance at January 1
Net Additions
Expenditures
Balance at December 31
2012
2011
2010
$ 1,404
428
(429)
$ 1,507
343
(446)
$ 1,700
220
(413)
$ 1,403
$ 1,404
$ 1,507
The company records asset retirement obligations when
there is a legal obligation associated with the retirement of
long-lived assets and the liability can be reasonably estimated.
These asset retirement obligations include costs related to
environmental issues. The liability balance of approximately
$13.3 billion for asset retirement obligations at year-end 2012
related primarily to upstream properties.
For the company’s other ongoing operating assets, such as
refineries and chemicals facilities, no provisions are made for
exit or cleanup costs that may be required when such assets
reach the end of their useful lives unless a decision to sell or
otherwise abandon the facility has been made, as the inde-
terminate settlement dates for the asset retirements prevent
estimation of the fair value of the asset retirement obligation.
Refer to the discussion below for additional information
on environmental matters and their impact on Chevron, and
on the company’s 2012 environmental expenditures. Refer to
Note 22 on pages 64 through 65 for additional discussion of
environmental remediation provisions and year-end reserves.
Refer also to Note 23 on page 66 for additional discussion of
the company’s asset retirement obligations.
Suspended Wells Information related to suspended
wells is included in Note 18 to the Consolidated Financial
Statements, Accounting for Suspended Wells, beginning on
page 55.
Income Taxes Information related to income tax con-
tingencies is included on pages 51 through 53 in Note 14 and
pages 63 through 64 in Note 22 to the Consolidated Finan-
cial Statements under the heading “Income Taxes.”
The American Taxpayer Relief Act of 2012 (the Act) was
signed into U.S. law on January 2, 2013. Several tax provi-
sions that expired at the end of 2011 were extended
retroactive to January 1, 2012, including the research and
development credit and certain rules for controlled foreign
corporations. There were no impacts from the Act included
in Chevron’s 2012 financial statements and the company does
not expect the impacts of the Act to have a material effect on
its results of operations, consolidated financial position or
liquidity in any future reporting period.
Other Contingencies Information related to other con-
tingencies is included on page 65 in Note 22 to the
Consolidated Financial Statements under the heading “Other
Contingencies.”
Environmental Matters
Virtually all aspects of the businesses in which the
company engages are subject to various international, fed-
eral, state and local environmental, health and safety laws,
regulations and market-based programs. These regulatory
requirements continue to increase in both number and com-
plexity over time and govern not only the manner in which
the company conducts its operations, but also the products it
sells. Regulations intended to address concerns about green-
house gas emissions and global climate change also continue
to evolve and include those at the international or multina-
tional (such as the mechanisms under the Kyoto Protocol and
the European Union’s Emissions Trading System), national
(such as the U.S. Environmental Protection Agency’s emis-
sion standards and renewable transportation fuel content
requirements or domestic market-based programs such as
those in effect in Australia and New Zealand), and state or
regional (such as California’s Global Warming Solutions Act)
levels.
Most of the costs of complying with laws and regulations
pertaining to company operations and products are embed-
ded in the normal costs of doing business. It is not possible to
predict with certainty the amount of additional investments
in new or existing facilities or amounts of incremental oper-
ating costs to be incurred in the future to: prevent, control,
reduce or eliminate releases of hazardous materials into the
environment; comply with existing and new environmental
laws or regulations; or remediate and restore areas damaged
by prior releases of hazardous materials. Although these costs
may be significant to the results of operations in any single
period, the company does not expect them to have a material
effect on the company’s liquidity or financial position.
Accidental leaks and spills requiring cleanup may occur
in the ordinary course of business. In addition to the costs
for environmental protection associated with its ongoing
operations and products, the company may incur expenses
for corrective actions at various owned and previously owned
facilities and at third-party-owned waste disposal sites used
by the company. An obligation may arise when operations
are closed or sold or at non-Chevron sites where company
products have been handled or disposed of. Most of the
expenditures to fulfill these obligations relate to facilities and
sites where past operations followed practices and procedures
Chevron Corporation 2012 Annual Report 23
Management’s Discussion and Analysis of
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Results of Operations
that were considered acceptable at the time but now require
investigative or remedial work or both to meet current stan-
dards.
Using definitions and guidelines established by the
American Petroleum Institute, Chevron estimated its world-
wide environmental spending in 2012 at approximately $2.8
billion for its consolidated companies. Included in these
expenditures were approximately $1.1 billion of environmen-
tal capital expenditures and $1.7 billion of costs associated
with the prevention, control, abatement or elimination of
hazardous substances and pollutants from operating, closed
or divested sites, and the abandonment and restoration of sites.
For 2013, total worldwide environmental capital expen-
ditures are estimated at $1.2 billion. These capital costs are
in addition to the ongoing costs of complying with envi-
ronmental regulations and the costs to remediate previously
contaminated sites.
Critical Accounting Estimates and Assumptions
Management makes many estimates and assumptions in
the application of generally accepted accounting principles
(GAAP) that may have a material impact on the company’s
consolidated financial statements and related disclosures
and on the comparability of such information over different
reporting periods. All such estimates and assumptions affect
reported amounts of assets, liabilities, revenues and expenses,
as well as disclosures of contingent assets and liabilities.
Estimates and assumptions are based on management’s expe-
rience and other information available prior to the issuance
of the financial statements. Materially different results can
occur as circumstances change and additional information
becomes known.
The discussion in this section of “critical” accounting
estimates and assumptions is according to the disclosure
guidelines of the Securities and Exchange Commission
(SEC), wherein:
1. the nature of the estimates and assumptions is mate-
rial due to the levels of subjectivity and judgment
necessary to account for highly uncertain matters
or the susceptibility of such matters to change; and
2. the impact of the estimates and assumptions on the
company’s financial condition or operating perfor-
mance is material.
The development and selection of accounting estimates
and assumptions, including those deemed “critical,” and the
associated disclosures in this discussion have been discussed
by management with the Audit Committee of the Board of
Directors. The areas of accounting and the associated “criti-
cal” estimates and assumptions made by the company are as
follows:
Pension and Other Postretirement Benefit Plans
The determination of pension plan obligations and expense
is based on a number of actuarial assumptions. Two critical
assumptions are the expected long-term rate of return on plan
assets and the discount rate applied to pension plan obliga-
tions. For other postretirement benefit (OPEB) plans, which
provide for certain health care and life insurance benefits
for qualifying retired employees and which are not funded,
critical assumptions in determining OPEB obligations and
expense are the discount rate and the assumed health care
cost-trend rates.
Note 20, beginning on page 57, includes information on
the funded status of the company’s pension and OPEB
plans at the end of 2012 and 2011; the components of pension
and OPEB expense for the three years ended December 31,
2012; and the underlying assumptions for those periods.
Pension and OPEB expense is reported on the Con-
solidated Statement of Income as “Operating expenses” or
“Selling, general and administrative expenses” and applies to
all business segments. The year-end 2012 and 2011 funded
status, measured as the difference between plan assets and
obligations, of each of the company’s pension and OPEB
plans is recognized on the Consolidated Balance Sheet. The
differences related to overfunded pension plans are reported
as a long-term asset in “Deferred charges and other assets.”
The differences associated with underfunded or unfunded
pension and OPEB plans are reported as “Accrued liabilities”
or “Reserves for employee benefit plans.” Amounts yet to be
recognized as components of pension or OPEB expense are
reported in “Accumulated other comprehensive loss.”
To estimate the long-term rate of return on pension
assets, the company uses a process that incorporates actual
historical asset-class returns and an assessment of expected
future performance and takes into consideration external
actuarial advice and asset-class factors. Asset allocations are
periodically updated using pension plan asset/liability stud-
ies, and the determination of the company’s estimates of
long-term rates of return are consistent with these studies. For
2012 the company used an expected long-term rate of return
of 7.5 percent for U.S. pension plan assets, which account
for 70 percent of the company’s pension plan assets. In 2011
and 2010, the company used a long-term rate of return of
7.8 percent for this plan. For the 10 years ending December
31, 2012, actual asset returns averaged 7.1 percent for this
plan. The actual return for 2012 was more than 7.5 percent
and was associated with a broad recovery in the financial mar-
kets during the year. Additionally, with the exception of two
other years within this 10-year period, actual asset returns for
this plan equaled or exceeded 7.5 percent.
The year-end market-related value of assets of the major
U.S. pension plan used in the determination of pension
24 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 25
expense was based on the market value in the preceding three
months. Management considers the three-month period long
enough to minimize the effects of distortions from day-to-
day market volatility and still be contemporaneous to the end
of the year. For other plans, market value of assets as of year-
end is used in calculating the pension expense.
The discount rate assumptions used to determine the U.S.
and international pension and postretirement benefit plan
obligations and expense reflect the rate at which benefits could
be effectively settled and is equal to the equivalent single rate
resulting from yield curve analysis. This analysis considered
the projected benefit payments specific to the company’s plans
and the yields on high-quality bonds. At December 31, 2012,
the company used a 3.6 percent discount rate for the U.S. pen-
sion plans and 3.9 percent for the main U.S. OPEB plan. The
discount rates at the end of 2011 and 2010 were 3.8 and 4.0
percent and 4.8 and 5.0 percent for the U.S. pension plans and
the main U.S. OPEB plans, respectively.
An increase in the expected long-term return on plan
assets or the discount rate would reduce pension plan
expense, and vice versa. Total pension expense for 2012 was
$1.3 billion. As an indication of the sensitivity of pension
expense to the long-term rate of return assumption, a 1 per-
cent increase in the expected rate of return on assets of the
company’s primary U.S. pension plan would have reduced
total pension plan expense for 2012 by approximately
$80 million. A 1 percent increase in the discount rate for
this same plan, which accounted for about 62 percent of the
companywide pension obligation, would have reduced total
pension plan expense for 2012 by approximately $165 million.
An increase in the discount rate would decrease the
pension obligation, thus changing the funded status of
a plan reported on the Consolidated Balance Sheet. The
aggregate funded status recognized on the Consolidated
Balance Sheet at December 31, 2012, was a net liability of
approximately $5.9 billion. As an indication of the sensitivity
of pension liabilities to the discount rate assumption, a 0.25
per cent increase in the discount rate applied to the com-
pany’s primary U.S. pension plan would have reduced the
plan obligation by approximately $335 million, which would
have decreased the plan’s underfunded status from approxi-
mately $2.6 billion to $2.2 billion. Other plans would be
less underfunded as discount rates increase. The actual rates
of return on plan assets and discount rates may vary signifi-
cantly from estimates because of unanticipated changes in
the world’s financial markets.
In 2012, the company’s pension plan contributions
were $1.2 billion (including $844 million to the U.S. plans).
In 2013, the company estimates contributions will be
approximately $1.0 billion. Actual contribution amounts are
dependent upon investment results, changes in pension obli-
gations, regulatory requirements and other economic factors.
Additional funding may be required if investment returns are
insufficient to offset increases in plan obligations.
For the company’s OPEB plans, expense for 2012 was
$172 million, and the total liability, which reflected the unfunded
status of the plans at the end of 2012, was $3.8 billion.
As an indication of discount rate sensitivity to the deter-
mination of OPEB expense in 2012, a 1 percent increase in
the discount rate for the company’s primary U.S. OPEB plan,
which accounted for about 82 percent of the companywide
OPEB expense, would have decreased OPEB expense by
approximately $17 million. A 0.25 percent increase in the
discount rate for the same plan, which accounted for about
83 percent of the companywide OPEB liabilities, would
have decreased total OPEB liabilities at the end of 2012 by
approximately $80 million.
For the main U.S. postretirement medical plan, the
annual increase to company contributions is limited to 4 per-
cent per year. For active employees and retirees under age 65
whose claims experiences are combined for rating purposes,
the assumed health care cost-trend rates start with 7.5 percent
in 2013 and gradually drop to 4.5 percent for 2025 and
beyond. As an indication of the health care cost-trend rate
sensitivity to the determination of OPEB expense in 2012, a
1 percent increase in the rates for the main U.S. OPEB plan,
would have increased OPEB expense by $15 million.
Differences between the various assumptions used to
determine expense and the funded status of each plan and
actual experience are not included in benefit plan costs in
the year the difference occurs. Instead, the differences are
included in actuarial gain/loss and unamortized amounts
have been reflected in “Accumulated other comprehensive
loss” on the Consolidated Balance Sheet. Refer to Note 20,
beginning on page 57, for information on the $9.7 bil-
lion of before-tax actuarial losses recorded by the company as
of December 31, 2012; a description of the method used to
amortize those costs; and an estimate of the costs to be rec-
ognized in expense during 2013.
Oil and Gas Reserves Crude oil and natural gas
reserves are estimates of future production that impact cer-
tain asset and expense accounts included in the Consolidated
Financial Statements. Proved reserves are the estimated quan-
tities of oil and gas that geoscience and engineering data
demonstrate with reasonable certainty to be economically
producible in the future under existing economic conditions,
operating methods and government regulations. Proved
reserves include both developed and undeveloped volumes.
Proved developed reserves represent volumes expected to be
recovered through existing wells with existing equipment and
operating methods. Proved undeveloped reserves are volumes
expected to be recovered from new wells on undrilled proved
acreage, or from existing wells where a relatively major expen-
diture is required for recompletion. Variables impacting
Chevron’s estimated volumes of crude oil and natural gas
reserves include field performance, available technology and
economic conditions.
The estimates of crude oil and natural gas reserves are
important to the timing of expense recognition for costs
incurred and to the valuation of certain oil and gas produc-
ing assets. Impacts of oil and gas reserves on Chevron’s
24 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 25
Management’s Discussion and Analysis of
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Results of Operations
Consolidated Financial Statements, using the successful
efforts method of accounting, include the following:
1. Amortization - Proved reserves are used in amortiz-
ing capitalized costs related to oil and gas producing
activities on the unit-of-production (UOP) method.
Capitalized exploratory drilling and development
costs are depreciated on a UOP basis using proved
developed reserves. Acquisition costs of proved proper-
ties are amortized on a UOP basis using total proved
reserves. During 2012, Chevron’s UOP Depreciation,
Depletion and Amortization (DD&A) for oil and gas
properties was $10.7 billion, and proved developed
reserves at the beginning of 2012 were 4.8 billion
barrels. If the estimates of proved reserves used in the
UOP calculations for consolidated operations had
been lower by 5 percent across all oil and gas proper-
ties, UOP DD&A in 2012 would have increased by
approximately $540 million.
2. Impairment - Oil and gas reserves are used in assess-
ing oil and gas producing properties for impairment.
A significant reduction in the estimated reserves of
a property would trigger an impairment review. In
assessing whether the property is impaired, the fair
value of the property must be determined. Frequently,
a discounted cash flow methodology is the best esti-
mate of fair value. Proved reserves (and, in some cases,
a portion of unproved resources) are used to estimate
future production volumes in the cash flow model.
For a further discussion of estimates and assumptions
used in impairment assessments, see Impairment of
Properties, Plant and Equipment and Investments in
Affiliates below.
Refer to Table V, “Reserve Quantity Information,” beginning
on page 76, for the changes in proved reserve estimates for
the three years ending December 31, 2012, and to Table VII,
“Changes in the Standardized Measure of Discounted Future
Net Cash Flows From Proved Reserves” on page 84 for esti-
mates of proved reserve values for each of the three years
ended December 31, 2012.
This Oil and Gas Reserves commentary should be read
in conjunction with the Properties, Plant and Equipment
section of Note 1 to the Consolidated Financial Statements,
beginning on page 36, which includes a description of the
“successful efforts” method of accounting for oil and gas
exploration and production activities.
Impairment of Properties, Plant and Equipment and
Investments in Affiliates The company assesses its proper-
ties, plant and equipment (PP&E) for possible impairment
whenever events or changes in circumstances indicate that
the carrying value of the assets may not be recoverable. Such
indicators include changes in the company’s business plans,
changes in commodity prices and, for crude oil and natural
gas properties, significant downward revisions of estimated
proved reserve quantities. If the carrying value of an asset
exceeds the future undiscounted cash flows expected from
the asset, an impairment charge is recorded for the excess of
carrying value of the asset over its estimated fair value.
Determination as to whether and how much an asset is
impaired involves management estimates on highly uncertain
matters, such as future commodity prices, the effects of infla-
tion and technology improvements on operating expenses,
production profiles, and the outlook for global or regional
market supply-and-demand conditions for crude oil, natural
gas, commodity chemicals and refined products. However,
the impairment reviews and calculations are based on
assumptions that are consistent with the company’s business
plans and long-term investment decisions. Refer also to the
discussion of impairments of properties, plant and equip-
ment in Note 8 beginning on page 41 and to the section on
Properties, Plant and Equipment in Note 1, Summary of Sig-
nificant Accounting Policies, beginning on page 36.
No material individual impairments of PP&E or Invest-
ments were recorded for the three years ending December
31, 2012. A sensitivity analysis of the impact on earnings for
these periods if other assumptions had been used in impair-
ment reviews and impairment calculations is not practicable,
given the broad range of the company’s PP&E and the
number of assumptions involved in the estimates. That is,
favorable changes to some assumptions might have avoided
the need to impair any assets in these periods, whereas unfa-
vorable changes might have caused an additional unknown
number of other assets to become impaired.
Investments in common stock of affiliates that are
accounted for under the equity method, as well as invest-
ments in other securities of these equity investees, are
reviewed for impairment when the fair value of the invest-
ment falls below the company’s carrying value. When such a
decline is deemed to be other than temporary, an impairment
charge is recorded to the income statement for the difference
between the investment’s carrying value and its estimated fair
value at the time.
26 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 27
In making the determination as to whether a decline
is other than temporary, the company considers such fac-
tors as the duration and extent of the decline, the investee’s
financial performance, and the company’s ability and
intention to retain its investment for a period that will
be sufficient to allow for any anticipated recovery in the
investment’s market value. Differing assumptions could
affect whether an investment is impaired in any period or
the amount of the impairment, and are not subject to sen-
sitivity analysis.
From time to time, the company performs impair-
ment reviews and determines whether any write-down in
the carrying value of an asset or asset group is required.
For example, when significant downward revisions to
crude oil and natural gas reserves are made for any single
field or concession, an impairment review is performed
to determine if the carrying value of the asset remains
recoverable. Also, if the expectation of sale of a particular
asset or asset group in any period has been deemed more
likely than not, an impairment review is performed, and
if the estimated net proceeds exceed the carrying value of
the asset or asset group, no impairment charge is required.
Such calculations are reviewed each period until the asset
or asset group is disposed of. Assets that are not impaired
on a held-and-used basis could possibly become impaired
if a decision is made to sell such assets. That is, the assets
would be impaired if they are classified as held-for-sale and
the estimated proceeds from the sale, less costs to sell, are
less than the assets’ associated carrying values.
Asset Retirement Obligations In the determination
of fair value for an asset retirement obligation (ARO),
the company uses various assumptions and judgments,
including such factors as the existence of a legal obligation,
estimated amounts and timing of settlements, discount
and inflation rates, and the expected impact of advances
in technology and process improvements. A sensitivity
analysis of the ARO impact on earnings for 2012 is not
practicable, given the broad range of the company’s long-
lived assets and the number of assumptions involved in the
estimates. That is, favorable changes to some assumptions
would have reduced estimated future obligations, thereby
lowering accretion expense and amortization costs, whereas
unfavorable changes would have the opposite effect. Refer
to Note 23 on page 66 for additional discussions on asset
retirement obligations.
Contingent Losses Management also makes judg-
ments and estimates in recording liabilities for claims,
litigation, tax matters and environmental remediation.
Actual costs can frequently vary from estimates for a
variety of reasons. For example, the costs for settlement
of claims and litigation can vary from estimates based on
differing interpretations of laws, opinions on culpability
and assessments on the amount of damages. Similarly,
liabilities for environmental remediation are subject to
change because of changes in laws, regulations and their
interpretation, the determination of additional informa-
tion on the extent and nature of site contamination, and
improvements in technology.
Under the accounting rules, a liability is generally
recorded for these types of contingencies if management
determines the loss to be both probable and estimable.
The company generally reports these losses as “Operating
expenses” or “Selling, general and administrative
expenses” on the Consolidated Statement of Income. An
exception to this handling is for income tax matters, for
which benefits are recognized only if management deter-
mines the tax position is “more likely than not” (i.e.,
likelihood greater than 50 percent) to be allowed by the
tax jurisdiction. For additional discussion of income tax
uncertainties, refer to Note 14 beginning on page 51.
Refer also to the business segment discussions elsewhere
in this section for the effect on earnings from losses asso-
ciated with certain litigation, environmen tal remediation
and tax matters for the three years ended December 31,
2012.
An estimate as to the sensitivity to earnings for these
periods if other assumptions had been used in recording
these liabilities is not practicable because of the number
of contingencies that must be assessed, the number of
underlying assumptions and the wide range of reasonably
possible outcomes, both in terms of the probability of loss
and the estimates of such loss.
New Accounting Standards
Refer to Note 17, on page 55 in the Notes to Consolidated
Financial Statements, for information regarding new
accounting standards.
26 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 27
Quarterly Results and Stock Market Data
Unaudited
Millions of dollars, except per-share amounts
4th Q
3rd Q
2nd Q
2012
1st Q
4th Q
3rd Q
2nd Q
2011
1st Q
Revenues and Other Income
Sales and other operating revenues1
Income from equity affiliates
Other income
Total Revenues and Other Income
Costs and Other Deductions
Purchased crude oil and products
Operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Taxes other than on income1
Interest and debt expense
Total Costs and Other Deductions
Income Before Income Tax Expense
Income Tax Expense
Net Income
Less: Net income attributable to
noncontrolling interests
Net Income Attributable to Chevron Corporation
Per Share of Common Stock
Net Income Attributable to Chevron Corporation
– Basic
– Diluted
Dividends
Common Stock Price Range – High2
– Low 2
1 Includes excise, value-added and similar taxes:
2 Intraday price.
$ 56,254 $ 55,660 $ 59,780 $ 58,896 $ 58,027
1,567
391
59,985
1,709
100
60,705
2,091
737
62,608
1,815
2,483
60,552
1,274
1,110
58,044
$ 61,261 $ 66,671 $ 58,412
1,687
242
60,341
1,882
395
68,948
2,227
944
64,432
36,053
5,183
940
403
3,205
2,852
–
33,959
6,273
1,182
357
3,554
3,251
–
48,576
11,976
4,679
36,363
5,948
1,330
386
3,313
2,680
–
48,636 50,020
12,069
9,965
5,570
4,813
$ 7,297 $ 5,308 $ 7,232 $ 6,499 $ 5,152
36,772
5,420
1,250
493
3,284
3,034
–
50,253
12,355
5,123
33,982
5,694
1,352
475
3,370
3,239
–
48,112
9,932
4,624
37,600
5,378
1,115
240
3,215
3,544
–
51,092
13,340
5,483
35,201
5,063
1,100
168
3,126
4,561
–
49,219
11,122
4,883
$ 7,857 $ 7,760 $ 6,239
40,759
5,260
1,200
422
3,257
4,843
–
55,741
13,207
5,447
52
29
$ 7,245 $ 5,253 $ 7,210 $ 6,471 $ 5,123
28
55
22
28
28
$ 7,829 $ 7,732 $ 6,211
28
$
$
3.73 $ 2.71 $
3.70 $ 2.69 $
3.68 $
3.66 $
2.61
2.58
$
$
3.94 $
3.92 $
3.88 $
3.85 $
3.11
3.09
0.90 $ 0.90 $
$
0.81
$ 118.38 $ 118.53 $ 108.79 $ 112.28 $ 110.01
$ 100.66 $ 103.29 $ 95.73 $ 102.08 $ 86.68
0.90 $
0.78 $
0.78 $
0.72
$
$ 109.75 $ 109.94 $ 109.65
$ 87.30 $ 97.00 $ 90.12
3.30 $
3.27 $
0.81 $
$
2,131
$
2,163
$
1,929
$
1,787 $
1,713
$
1,974 $
2,264
$
2,134
The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 11, 2013,
stockholders of record numbered approximately 168,000. There are no restrictions on the company’s ability to pay dividends.
28 Chevron Corporation 2012 Annual Report
Management’s Responsibility for Financial Statements
To the Stockholders of Chevron Corporation
Management of Chevron is responsible for preparing the accompanying consolidated financial statements and the related informa-
tion appearing in this report. The statements were prepared in accordance with accounting principles generally accepted in the
United States of America and fairly represent the transactions and financial position of the company. The financial statements
include amounts that are based on management’s best estimates and judgment.
As stated in its report included herein, the independent registered public accounting firm of PricewaterhouseCoopers LLP
has audited the company’s consolidated financial statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States).
The Board of Directors of Chevron has an Audit Committee composed of directors who are not officers or employees of the
company. The Audit Committee meets regularly with members of management, the internal auditors and the independent registered
public accounting firm to review accounting, internal control, auditing and financial reporting matters. Both the internal auditors
and the independent registered public accounting firm have free and direct access to the Audit Committee without the presence of
management.
Management’s Report on Internal Control Over Financial Reporting
The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting,
as such term is defined in Exchange Act Rule 13a-15(f). The company’s management, including the Chief Executive Officer and
Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting
based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on the results of this evaluation, the company’s management concluded that internal control over financial
reporting was effective as of December 31, 2012.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2012, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.
John S. Watson
Chairman of the Board
and Chief Executive Officer
February 22, 2013
Patricia E. Yarrington
Vice President
and Chief Financial Officer
Matthew J. Foehr
Vice President
and Comptroller
PB Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 29
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Chevron Corporation:
In our opinion, the accompanying consolidated balance
sheet and the related consolidated statements of income,
comprehensive income, equity and of cash flows present
fairly, in all material respects, the financial position of
Chevron Corporation and its subsidiaries at December
31, 2012, and December 31, 2011, and the results of their
operations and their cash flows for each of the three years
in the period ended December 31, 2012, in conformity
with accounting principles generally accepted in the United
States of America. Also in our opinion, the Company
maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2012, based on
criteria established in Internal Control – Integrated Framework
issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO). The Company’s
management is responsible for these financial statements,
for maintaining effective internal control over financial
reporting, and for its assessment of the effectiveness of
internal control over financial reporting, included in the
accompanying Management’s Report on Internal Control
Over Financial Reporting. Our responsibility is to express
opinions on these financial statements and on the Company’s
internal control over financial reporting based on our
integrated audits. We conducted our audits in accordance
with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require
that we plan and perform the audits to obtain reasonable
assurance about whether the financial statements are free of
material misstatement and whether effective internal control
over financial reporting was maintained in all material
respects. Our audits of the financial statements included
examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. Our audit of internal control over financial
reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a
material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based
on the assessed risk. Our audits also included performing
such other procedures as we considered necessary in
the circumstances. We believe that our audits provide a
reasonable basis for our opinions.
A 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 (i) pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company;
(ii) 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 (iii) 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.
San Francisco, California
February 22, 2013
30 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 31
Consolidated Statement of Income
Millions of dollars, except per-share amounts
Revenues and Other Income
Sales and other operating revenues*
Income from equity affiliates
Other income
Total Revenues and Other Income
Costs and Other Deductions
Purchased crude oil and products
Operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Taxes other than on income*
Interest and debt expense
Total Costs and Other Deductions
Income Before Income Tax Expense
Income Tax Expense
Net Income
Less: Net income attributable to noncontrolling interests
Net Income Attributable to Chevron Corporation
Per Share of Common Stock
Net Income Attributable to Chevron Corporation
– Basic
– Diluted
* Includes excise, value-added and similar taxes.
See accompanying Notes to the Consolidated Financial Statements.
Year ended December 31
2011
2010
2012
$ 230,590
6,889
4,430
241,909
140,766
22,570
4,724
1,728
13,413
12,376
–
195,577
46,332
19,996
26,336
157
$ 26,179
$ 244,371
7,363
1,972
253,706
149,923
21,649
4,745
1,216
12,911
15,628
–
206,072
47,634
20,626
27,008
113
$ 26,895
$
$
$
13.42
13.32
8,010
$
$
$
13.54
13.44
8,085
$ 198,198
5,637
1,093
204,928
116,467
19,188
4,767
1,147
13,063
18,191
50
172,873
32,055
12,919
19,136
112
$ 19,024
$
$
$
9.53
9.48
8,591
30 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 31
Consolidated Statement of Comprehensive Income
Millions of dollars
Net Income
Currency translation adjustment
Unrealized net change arising during period
Unrealized holding gain (loss) on securities
Net gain (loss) arising during period
Derivatives
Net derivatives gain on hedge transactions
Reclassification to net income of net realized (gain) loss
Income taxes on derivatives transactions
Total
Defined benefit plans
Actuarial loss
Amortization to net income of net actuarial loss
Actuarial loss arising during period
Prior service cost
Amortization to net income of net prior service credits
Prior service cost arising during period
Defined benefit plans sponsored by equity affiliates
Income taxes on defined benefit plans
Total
Other Comprehensive Loss, Net of Tax
Comprehensive Income
Comprehensive income attributable to noncontrolling interests
Comprehensive Income Attributable to Chevron Corporation
See accompanying Notes to the Consolidated Financial Statements.
2012
$ 26,336
Year ended December 31
2011
$ 27,008
2010
$ 19,136
23
1
20
(14)
(3)
3
920
(1,180)
(61)
(142)
(54)
143
(374)
(347)
25,989
(157)
$ 25,832
17
(11)
20
9
(10)
19
773
(3,250)
(26)
(27)
(81)
1,030
(1,581)
(1,556)
25,452
(113)
$ 25,339
6
(4)
25
5
(10)
20
635
(857)
(61)
(12)
(12)
140
(167)
(145)
18,991
(112)
$ 18,879
32 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 33
Consolidated Balance Sheet
Millions of dollars, except per-share amounts
Assets
Cash and cash equivalents
Time deposits
Marketable securities
Accounts and notes receivable (less allowance: 2012 – $80; 2011 – $98)
Inventories:
Crude oil and petroleum products
Chemicals
Materials, supplies and other
Total inventories
Prepaid expenses and other current assets
Total Current Assets
Long-term receivables, net
Investments and advances
Properties, plant and equipment, at cost
Less: Accumulated depreciation, depletion and amortization
Properties, plant and equipment, net
Deferred charges and other assets
Goodwill
Total Assets
Liabilities and Equity
Short-term debt
Accounts payable
Accrued liabilities
Federal and other taxes on income
Other taxes payable
Total Current Liabilities
Long-term debt
Capital lease obligations
Deferred credits and other noncurrent obligations
Noncurrent deferred income taxes
Reserves for employee benefit plans
Total Liabilities
Preferred stock (authorized 100,000,000 shares; $1.00 par value; none issued)
Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares
issued at December 31, 2012 and 2011)
Capital in excess of par value
Retained earnings
Accumulated other comprehensive loss
Deferred compensation and benefit plan trust
Treasury stock, at cost (2012 – 495,978,691 shares; 2011 – 461,509,656 shares)
Total Chevron Corporation Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
See accompanying Notes to the Consolidated Financial Statements.
At December 31
2012
2011
$ 20,939
708
266
20,997
3,923
475
1,746
6,144
6,666
55,720
3,053
23,718
263,481
122,133
141,348
4,503
4,640
$ 232,982
$
127
22,776
5,738
4,341
1,230
34,212
11,966
99
21,502
17,672
9,699
95,150
–
1,832
15,497
159,730
(6,369)
(282)
(33,884)
136,524
1,308
137,832
$ 232,982
$ 15,864
3,958
249
21,793
3,420
502
1,621
5,543
5,827
53,234
2,233
22,868
233,432
110,824
122,608
3,889
4,642
$ 209,474
$
340
22,147
5,287
4,584
1,242
33,600
9,684
128
19,181
15,544
9,156
87,293
–
1,832
15,156
140,399
(6,022)
(298)
(29,685)
121,382
799
122,181
$ 209,474
32 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 33
Consolidated Statement of Cash Flows
Millions of dollars
Operating Activities
Net Income
Adjustments
Depreciation, depletion and amortization
Dry hole expense
Distributions less than income from equity affiliates
Net before-tax gains on asset retirements and sales
Net foreign currency effects
Deferred income tax provision
Net decrease in operating working capital
Increase in long-term receivables
Decrease in other deferred charges
Cash contributions to employee pension plans
Other
Net Cash Provided by Operating Activities
Investing Activities
Acquisition of Atlas Energy
Advance to Atlas Energy
Capital expenditures
Proceeds and deposits related to asset sales
Net sales (purchases) of time deposits
Net purchases of marketable securities
Repayment of loans by equity affiliates
Net purchases of other short-term investments
Net Cash Used for Investing Activities
Financing Activities
Net borrowings (payments) of short-term obligations
Proceeds from issuances of long-term debt
Repayments of long-term debt and other financing obligations
Cash dividends – common stock
Distributions to noncontrolling interests
Net purchases of treasury shares
Net Cash Used for Financing Activities
Effect of Exchange Rate Changes on Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents
Cash and Cash Equivalents at January 1
Cash and Cash Equivalents at December 31
See accompanying Notes to the Consolidated Financial Statements.
2012
2011
2010
Year ended December 31
$ 26,336
$ 27,008
$ 19,136
13,413
555
(1,351)
(4,089)
207
2,015
363
(169)
1,047
(1,228)
1,713
38,812
–
–
(30,938)
2,777
3,250
(3)
328
(210)
(24,796)
264
4,007
(2,224)
(6,844)
(41)
(4,142)
(8,980)
39
5,075
15,864
$ 20,939
12,911
377
(570)
(1,495)
(103)
1,589
2,318
(150)
341
(1,467)
336
41,095
(3,009)
(403)
(26,500)
3,517
(1,104)
(74)
339
(255)
(27,489)
23
377
(2,769)
(6,136)
(71)
(3,193)
(11,769)
(33)
1,804
14,060
$ 15,864
13,063
496
(501)
(1,004)
251
559
76
(12)
48
(1,450)
692
31,354
–
–
(19,612)
1,995
(2,855)
(49)
338
(732)
(20,915)
(212)
1,250
(156)
(5,669)
(72)
(306)
(5,165)
70
5,344
8,716
$ 14,060
34 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 35
Consolidated Statement of Equity
Shares in thousands; amounts in millions of dollars
Preferred Stock
Common Stock
Capital in Excess of Par
Balance at January 1
Treasury stock transactions
Balance at December 31
Retained Earnings
Balance at January 1
Net income attributable to Chevron Corporation
Cash dividends on common stock
Stock dividends
Tax (charge) benefit from dividends paid on
unallocated ESOP shares and other
Balance at December 31
Accumulated Other Comprehensive Loss
Currency translation adjustment
Balance at January 1
Change during year
Balance at December 31
Pension and other postretirement benefit plans
Balance at January 1
Change during year
Balance at December 31
Unrealized net holding gain on securities
Balance at January 1
Change during year
Balance at December 31
Net derivatives gain (loss) on hedge transactions
Balance at January 1
Change during year
Balance at December 31
Balance at December 31
Deferred Compensation and Benefit Plan Trust
Deferred Compensation
Balance at January 1
Net reduction of ESOP debt and other
Balance at December 31
Benefit Plan Trust (Common Stock)
Balance at December 31
Treasury Stock at Cost
Balance at January 1
Purchases
Issuances – mainly employee benefit plans
Balance at December 31
Total Chevron Corporation Stockholders’ Equity
at December 31
Noncontrolling Interests
Total Equity
See accompanying Notes to the Consolidated Financial Statements.
2012
2011
2010
Shares
Amount
Shares
Amount
Shares
Amount
–
2,442,677
$
$
–
1,832
–
2,442,677
$
$
–
1,832
–
2,442,677
$
$
–
1,832
$ 15,156
341
$ 15,497
$ 140,399
26,179
(6,844)
(3)
(1)
$ 159,730
$
$
$
$
$
$
$
$
$
$
$
(88)
23
(65)
(6,056)
(374)
(6,430)
–
1
1
122
3
125
(6,369)
(58)
16
(42)
(240)
(282)
$ (29,685)
(5,004)
805
$ (33,884)
$ 136,524
$
1,308
$ 137,832
14,168
14,168
461,510
46,669
(12,200)
495,979
$ 14,796
360
$ 15,156
$ 119,641
26,895
(6,136)
(3)
2
$ 140,399
$
$
$
$
$
$
$
$
$
$
$
(105)
17
(88)
(4,475)
(1,581)
(6,056)
11
(11)
–
103
19
122
(6,022)
(71)
13
(58)
(240)
(298)
$ (26,411)
(4,262)
988
$ (29,685)
$ 121,382
$
799
$ 122,181
$ 14,631
165
$ 14,796
$ 106,289
19,024
(5,669)
(5)
2
$ 119,641
$
$
$
$
$
$
$
$
$
$
$
(111)
6
(105)
(4,308)
(167)
(4,475)
15
(4)
11
83
20
103
(4,466)
(109)
38
(71)
(240)
(311)
$ (26,168)
(775)
532
$ (26,411)
$ 105,081
$
730
$ 105,811
14,168
14,168
434,955
9,091
(8,850)
435,196
14,168
14,168
435,196
42,424
(16,110)
461,510
34 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 35
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 1
Summary of Significant Accounting Policies
General Upstream operations consist primarily of explor-
ing for, developing and producing crude oil and natural gas;
liquefaction, transportation and regasification associated with
liquefied natural gas (LNG); transporting crude oil by major
international oil export pipelines; processing, transporting,
storage and marketing of natural gas; and a gas-to-liquids
project. Downstream operations relate primarily to refin-
ing crude oil into petroleum products; marketing of crude
oil and refined products; transporting crude oil and refined
products by pipeline, marine vessel, motor equipment and
rail car; and manufacturing and marketing of commodity
petrochemicals, plastics for industrial uses, and additives for
fuels and lubricant oils.
The company’s Consolidated Financial Statements are
prepared in accordance with accounting principles gener-
ally accepted in the United States of America. These require
the use of estimates and assumptions that affect the assets,
liabilities, revenues and expenses reported in the financial
statements, as well as amounts included in the notes thereto,
including discussion and disclosure of contingent liabilities.
Although the company uses its best estimates and judgments,
actual results could differ from these estimates as future con-
firming events occur.
Subsidiary and Affiliated Companies The Consolidated
Financial Statements include the accounts of controlled sub-
sidiary companies more than 50 percent-owned and any
variable-interest entities in which the company is the primary
beneficiary. Undivided interests in oil and gas joint ventures
and certain other assets are consolidated on a proportionate
basis. Investments in and advances to affiliates in which the
company has a substantial ownership interest of approxi-
mately 20 percent to 50 percent, or for which the company
exercises significant influence but not control over policy
decisions, are accounted for by the equity method. As part of
that accounting, the company recognizes gains and losses
that arise from the issuance of stock by an affiliate that
results in changes in the company’s proportionate share of
the dollar amount of the affiliate’s equity currently in income.
Investments are assessed for possible impairment when
events indicate that the fair value of the investment may be
below the company’s carrying value. When such a condition
is deemed to be other than temporary, the carrying value of
the investment is written down to its fair value, and the
amount of the write-down is included in net income. In
making the determination as to whether a decline is other
than temporary, the company considers such factors as the
duration and extent of the decline, the investee’s financial
performance, and the company’s ability and intention to
retain its investment for a period that will be sufficient to
36 Chevron Corporation 2012 Annual Report
allow for any anticipated recovery in the investment’s market
value. The new cost basis of investments in these equity
investees is not changed for subsequent recoveries in fair value.
Differences between the company’s carrying value of an
equity investment and its underlying equity in the net assets
of the affiliate are assigned to the extent practicable to specific
assets and liabilities based on the company’s analysis of the
various factors giving rise to the difference. When appro priate,
the company’s share of the affiliate’s reported earnings is
adjusted quarterly to reflect the difference between these allo-
cated values and the affiliate’s historical book values.
Derivatives The majority of the company’s activity in
derivative commodity instruments is intended to manage
the financial risk posed by physical transactions. For some
of this derivative activity, generally limited to large, discrete
or infrequently occurring transactions, the company may
elect to apply fair value or cash flow hedge accounting. For
other similar derivative instruments, generally because of
the short-term nature of the contracts or their limited use,
the company does not apply hedge accounting, and changes
in the fair value of those contracts are reflected in current
income. For the company’s commodity trading activity,
gains and losses from derivative instruments are reported in
current income. The company may enter into interest rate
swaps from time to time as part of its overall strategy to
manage the interest rate risk on its debt. Interest rate swaps
related to a portion of the company’s fixed-rate debt, if any,
may be accounted for as fair value hedges. Interest rate swaps
related to floating-rate debt, if any, are recorded at fair value
on the balance sheet with resulting gains and losses reflected
in income. Where Chevron is a party to master netting
arrangements, fair value receivable and payable amounts rec-
ognized for derivative instruments executed with the same
counterparty are generally offset on the balance sheet.
Short-Term Investments All short-term investments are
classified as available for sale and are in highly liquid debt
securities. Those investments that are part of the company’s
cash management portfolio and have original maturities
of three months or less are reported as “Cash equivalents.”
Bank time deposits with maturities greater than 90 days
are reported as “Time deposits.” The balance of short-term
investments is reported as “Marketable securities” and is
marked-to-market, with any unrealized gains or losses
included in “Other comprehensive income.”
Inventories Crude oil, petroleum products and chemicals
inventories are generally stated at cost, using a last-in, first-
out method. In the aggregate, these costs are below market.
“Materials, supplies and other” inventories generally are
stated at average cost.
Chevron Corporation 2012 Annual Report 37
Note 1 Summary of Significant Accounting Policies – Continued
Properties, Plant and Equipment The successful efforts
method is used for crude oil and natural gas exploration and
production activities. All costs for development wells, related
plant and equipment, proved mineral interests in crude oil
and natural gas properties, and related asset retirement obli-
gation (ARO) assets are capitalized. Costs of exploratory
wells are capitalized pending determination of whether the
wells found proved reserves. Costs of wells that are assigned
proved reserves remain capitalized. Costs also are capitalized
for exploratory wells that have found crude oil and natural
gas reserves even if the reserves cannot be classified as proved
when the drilling is completed, provided the exploratory
well has found a sufficient quantity of reserves to justify its
completion as a producing well and the company is making
sufficient progress assessing the reserves and the economic
and operating viability of the project. All other exploratory
wells and costs are expensed. Refer to Note 18, beginning
on page 55, for additional discussion of accounting for
suspended exploratory well costs.
Long-lived assets to be held and used, including proved
crude oil and natural gas properties, are assessed for possible
impairment by comparing their carrying values with their
asso ciated undiscounted, future net before-tax cash flows.
Events that can trigger assessments for possible impairments
include write-downs of proved reserves based on field per-
formance, significant decreases in the market value of an
asset, significant change in the extent or manner of use of
or a physical change in an asset, and a more-likely-than-not
expectation that a long-lived asset or asset group will be sold
or otherwise disposed of significantly sooner than the end
of its previously estimated useful life. Impaired assets are
written down to their estimated fair values, generally their
discounted, future net before-tax cash flows. For proved
crude oil and natural gas properties in the United States,
the company generally performs an impairment review on
an individual field basis. Outside the United States, reviews
are performed on a country, concession, development area
or field basis, as appropriate. In Downstream, impairment
reviews are performed on the basis of a refinery, a plant, a
marketing/lubricants area or distribution area, as appropriate.
Impairment amounts are recorded as incremental “Deprecia-
tion, depletion and amortization” expense.
Long-lived assets that are held for sale are evaluated for
possible impairment by comparing the carrying value of the
asset with its fair value less the cost to sell. If the net book
value exceeds the fair value less cost to sell, the asset is consid-
ered impaired and adjusted to the lower value. Refer to Note 8,
beginning on page 41, relating to fair value measurements.
The fair value of a liability for an ARO is recorded as an
asset and a liability when there is a legal obligation associated
with the retirement of a long-lived asset and the amount can
be reasonably estimated. Refer also to Note 23, on page 66,
relating to AROs.
Depreciation and depletion of all capitalized costs of
proved crude oil and natural gas producing properties, except
mineral interests, are expensed using the unit-of-produc-
tion method, generally by individual field, as the proved
developed reserves are produced. Depletion expenses for
capitalized costs of proved mineral interests are recognized
using the unit-of-production method by individual field as
the related proved reserves are produced. Periodic valuation
provisions for impairment of capitalized costs of unproved
mineral interests are expensed.
The capitalized costs of all other plant and equipment
are depreciated or amortized over their estimated useful
lives. In general, the declining-balance method is used to
depreciate plant and equipment in the United States; the
straight-line method is generally used to depreciate interna-
tional plant and equipment and to amortize all capitalized
leased assets.
Gains or losses are not recognized for normal retirements
of properties, plant and equipment subject to composite
group amortization or depreciation. Gains or losses from
abnormal retirements are recorded as expenses, and from
sales as “Other income.”
Expenditures for maintenance (including those for
planned major maintenance projects), repairs and minor
renewals to maintain facilities in operating condition are
generally expensed as incurred. Major replacements and
renewals are capitalized.
Goodwill Goodwill resulting from a business combination
is not subject to amortization. As required by accounting
standards for goodwill (ASC 350), the company tests such
goodwill at the reporting unit level for impairment on an
annual basis and between annual tests if an event occurs or
circumstances change that would more likely than not reduce
the fair value of the reporting unit below its carrying amount.
Environmental Expenditures Environmental expenditures
that relate to ongoing operations or to conditions caused by
past operations are expensed. Expenditures that create future
benefits or contribute to future revenue generation are capital-
ized.
Liabilities related to future remediation costs are recorded
when environmental assessments or cleanups or both are
probable and the costs can be reasonably estimated. For the
company’s U.S. and Canadian marketing facilities, the accrual
is based in part on the probability that a future remediation
commitment will be required. For crude oil, natural gas and
36 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 37
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 1 Summary of Significant Accounting Policies – Continued
mineral-producing properties, a liability for an ARO is made
in accordance with accounting standards for asset retirement
and environmental obligations. Refer to Note 23, on
page 66, for a discussion of the company’s AROs.
For federal Superfund sites and analogous sites under
state laws, the company records a liability for its designated
share of the probable and estimable costs, and probable
amounts for other potentially responsible parties when man-
dated by the regulatory agencies because the other parties are
not able to pay their respective shares.
The gross amount of environmental liabilities is based
on the company’s best estimate of future costs using currently
available technology and applying current regulations and
the company’s own internal environmental policies. Future
amounts are not discounted. Recoveries or reimbursements
are recorded as assets when receipt is reasonably assured.
Currency Translation The U.S. dollar is the functional
currency for substantially all of the company’s consolidated
operations and those of its equity affiliates. For those opera-
tions, all gains and losses from currency remeasurement are
included in current period income. The cumulative trans-
lation effects for those few entities, both consolidated and
affiliated, using functional currencies other than the U.S.
dollar are included in “Currency translation adjustment” on
the Consolidated Statement of Equity.
Revenue Recognition Revenues associated with sales of
crude oil, natural gas, petroleum and chemicals products,
and all other sources are recorded when title passes to the
customer, net of royalties, discounts and allowances, as
applicable. Revenues from natural gas production from prop-
erties in which Chevron has an interest with other producers
are generally recognized using the entitle ment method. Excise,
value-added and similar taxes assessed by a governmental
authority on a revenue- producing transaction between a seller
and a customer are presented on a gross basis. The associated
amounts are shown as a footnote to the Consolidated State-
ment of Income, on page 31. Purchases and sales of
inventory with the same counterparty that are entered into
in contemplation of one another (including buy/sell arrange-
ments) are combined and recorded on a net basis and reported
in “Purchased crude oil and products” on the Consolidated
Statement of Income.
Stock Options and Other Share-Based Compensation The
company issues stock options and other share-based compen-
sation to its employees and accounts for these transactions
under the accounting standards for share-based compensa-
tion (ASC 718). For equity awards, such as stock options,
total compensation cost is based on the grant date fair value,
and for liability awards, such as stock appreciation rights,
total compensation cost is based on the settlement value. The
company recognizes stock-based compensation expense for
all awards over the service period required to earn the award,
which is the shorter of the vesting period or the time period
an employee becomes eligible to retain the award at retire-
ment. Stock options and stock appreciation rights granted
under the company’s Long-Term Incentive Plan have graded
vesting provisions by which one-third of each award vests on
the first, second and third anniversaries of the date of grant.
The company amortizes these graded awards on a straight-
line basis.
Note 2
Noncontrolling Interests
Ownership interests in the company’s subsidiaries held by
parties other than the parent are presented separately from
the parent’s equity on the Consolidated Balance Sheet. The
amount of consolidated net income attributable to the par-
ent and the noncontrolling interests are both presented on
the face of the Consolidated Statement of Income. The term
“earnings” is defined as “Net Income Attributable to Chevron
Corporation.”
Activity for the equity attributable to noncontrolling
interests for 2012, 2011 and 2010 is as follows:
2012
2011
2010
Balance at January 1
Net income
Distributions to noncontrolling interests
Other changes, net*
Balance at December 31
$ 799
157
(41)
393
$ 1,308
$ 730
113
(71)
27
$ 799
$ 647
112
(72)
43
$ 730
* Includes components of comprehensive income, which are disclosed separately in the
Consolidated Statement of Comprehensive Income.
38 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 39
Note 3
Information Relating to the Consolidated Statement of Cash Flows
Year ended December 31
2012
2011
2010
Net decrease (increase) in operating
working capital was composed of the
following:
Decrease (increase) in accounts and
notes receivable
(Increase) decrease in inventories
Increase in prepaid expenses and
other current assets
Increase in accounts payable
and accrued liabilities
(Decrease) increase in income and
other taxes payable
Net decrease in operating
working capital
Net cash provided by operating
activities includes the following
cash payments for interest and
income taxes:
Interest paid on debt
(net of capitalized interest)
Income taxes
Net sales of marketable securities
consisted of the following
gross amounts:
Marketable securities purchased
Marketable securities sold
Net purchases of marketable
securities
$ 1,153
$ (2,156) $ (2,767)
15
(404)
(233)
(471)
(853)
(542)
544
3,839
3,049
(630)
1,892
321
$
363
$ 2,318
$
76
$
–
$ 17,334
$
–
$ 17,374
$
34
$ 11,749
$
(35) $
32
(112) $
38
(90)
41
$
(3) $
(74) $
(49)
Net sales (purchases) of time deposits
consisted of the following
gross amounts:
$
Time deposits purchased
3,967
Time deposits matured
Net sales (purchases) of time deposits $ 3,250
(717) $ (6,439) $ (5,060)
2,205
$ (1,104) $ (2,855)
5,335
In accordance with accounting standards for cash-flow clas-
sifications for stock options (ASC 718), the “Net decrease
in operating working capital” includes reductions of $98,
$121 and $67 for excess income tax benefits associated with
stock options exercised during 2012, 2011 and 2010, respec-
tively. These amounts are offset by an equal amount in “Net
purchases of treasury shares.” “Other” includes changes
in postretirement benefits obligations and other long-term
liabilities.
The “Acquisition of Atlas Energy” reflects the $3,009
of cash paid for all the common shares of Atlas in Febru-
ary 2011. An “Advance to Atlas Energy” of $403 was made
to facilitate the purchase of a 49 percent interest in Laurel
Mountain Midstream LLC on the day of closing. The “Net
decrease (increase) in operating working capital” includes
$184 for payments made in connection with Atlas equity
awards subsequent to the acquisition. Refer to Note 26,
beginning on page 68 for additional discussion of the Atlas
acquisition.
The “Repayments of long-term debt and other financing
obligations” in 2011 includes $761 for repayment of Atlas
debt and $271 for payoff of the Atlas revolving credit facility.
The “Net purchases of treasury shares” represents the cost
of common shares acquired less the cost of shares issued for
share-based compensation plans. Purchases totaled $5,004,
$4,262 and $775 in 2012, 2011 and 2010, respectively. In 2012
and 2011, the company purchased 46.6 million and 42.3 mil-
lion common shares for $5,000 and $4,250 under its ongoing
share repurchase program, respectively.
In 2012 and 2011, “Net purchases of other short-term
investments” consist of restricted cash associated with tax pay-
ments, upstream abandonment activities, funds held in escrow
for an asset acquisition and capital investment projects that was
invested in short-term securities and reclassified from “Cash
and cash equivalents” to “Deferred charges and other assets”
on the Consolidated Balance Sheet. The company issued $374
and $1,250 in 2011 and 2010, respectively, of tax exempt
bonds as a source of funds for U.S. refinery projects, which is
included in “Proceeds from issuance of long-term debt.”
The Consolidated Statement of Cash Flows excludes
changes to the Consolidated Balance Sheet that did not affect
cash. The 2012 period excludes the effects of $800 of proceeds
to be received in future periods for the sale of an equity inter-
est in the Wheatstone Project. “Capital expenditures” in the
2012 period excludes a $1,850 increase in “Properties, plant
and equipment” related to an upstream asset exchange in Aus-
tralia. Refer also to Note 23, on page 66, for a discussion of
revisions to the company’s AROs that also did not involve
cash receipts or payments for the three years ending December 31,
2012.
38 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 39
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 3 Information Relating to the Consolidated Statement of Cash Flows – Continued
The major components of “Capital expenditures” and
The summarized financial information for CUSA and its
the reconciliation of this amount to the reported capital and
exploratory expenditures, including equity affiliates, are
presented in the following table:
Additions to properties, plant
and equipment*
Additions to investments
Current-year dry hole expenditures
Payments for other liabilities
and assets, net
Capital expenditures
Expensed exploration expenditures
Assets acquired through capital
lease obligations and other
financing obligations
Capital and exploratory expenditures,
excluding equity affiliates
Company’s share of expenditures
by equity affiliates
Capital and exploratory expenditures,
including equity affiliates
Year ended December 31
2012
2011
2010
$ 29,526
1,042
475
$ 25,440
900
332
$ 18,474
861
414
(105)
30,938
1,173
(172)
26,500
839
(137)
19,612
651
1
32
104
32,112
27,371
20,367
2,117
1,695
1,388
$ 34,229
$ 29,066
$ 21,755
*Excludes noncash additions of $4,569 in 2012, $945 in 2011 and $2,753 in 2010.
Note 4
Summarized Financial Data — Chevron U.S.A. Inc.
Chevron U.S.A. Inc. (CUSA) is a major subsidiary of
Chevron Corporation. CUSA and its subsidiaries manage
and operate most of Chevron’s U.S. businesses. Assets include
those related to the exploration and production of crude oil,
natural gas and natural gas liquids and those associated with
the refining, marketing, supply and distribution of products
derived from petroleum, excluding most of the regulated
pipeline operations of Chevron. CUSA also holds the
company’s investment in the Chevron Phillips Chemical
Company LLC joint venture, which is accounted for using
the equity method.
During 2012, Chevron implemented legal reorganiza-
tions in which certain Chevron subsidiaries transferred assets
to or under CUSA. The summarized financial information
for CUSA and its consolidated subsidiaries presented in the
table below gives retroactive effect to the reorganizations as if
they had occurred on January 1, 2010. However, the financial
information in the following table may not reflect the financial
position and operating results in the periods presented if the
reorganization had occurred on that date.
consolidated subsidiaries is as follows:
Year ended December 31
2012
2011
2010
Sales and other operating
revenues
Total costs and other deductions
Net income attributable to CUSA
$ 183,215 $ 187,929 $ 143,352
175,009 178,510
137,964
4,154
6,898
6,216
Current assets
Other assets
Current liabilities
Other liabilities
Total CUSA net equity
Memo: Total debt
At December 31
2012
2011
$ 18,983 $ 34,490
47,556
19,081
26,160
$ 26,432 $ 36,805
52,082
18,161
26,472
$ 14,482 $ 14,763
Note 5
Summarized Financial Data — Chevron Transport Corporation Ltd.
Chevron Transport Corporation Ltd. (CTC), incorporated in
Bermuda, is an indirect, wholly owned subsidiary of Chevron
Corporation. CTC is the principal operator of Chevron’s inter-
national tanker fleet and is engaged in the marine transportation
of crude oil and refined petroleum products. Most of CTC’s
shipping revenue is derived from providing transportation serv-
ices to other Chevron companies. Chevron Corporation has
fully and unconditionally guaranteed this subsidiary’s obliga-
tions in connection with certain debt securities issued by a third
party. Summarized financial information for CTC and its
consolidated subsidiaries is as follows:
Year ended December 31
2012
2011
2010
Sales and other operating revenues
Total costs and other deductions
Net loss attributable to CTC
$ 606
745
(135)
$ 793
974
(177)
$ 885
1,008
(116)
Current assets
Other assets
Current liabilities
Other liabilities
Total CTC net (deficit) equity
At December 31
2012
$ 199
313
154
415
$ (57)
2011
$ 290
228
114
346
$ 58
There were no restrictions on CTC’s ability to pay divi-
dends or make loans or advances at December 31, 2012.
40 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 41
Note 6
Summarized Financial Data — Tengizchevroil LLP
Chevron has a 50 percent equity ownership interest in
Tengizchevroil LLP (TCO). Refer to Note 11, on page 46,
for a discussion of TCO operations.
Summarized financial information for 100 percent of
TCO is presented in the following table:
Year ended December 31
2012
2011
2010
Sales and other operating revenues
Costs and other deductions
Net income attributable to TCO
$ 23,089
10,064
9,119
$ 25,278
10,941
10,039
$ 17,812
8,394
6,593
Contingent rentals are based on factors other than the pas-
sage of time, principally sales volumes at leased service stations.
Certain leases include escalation clauses for adjusting rentals to
reflect changes in price indices, renewal options ranging up to
25 years, and options to purchase the leased property during or
at the end of the initial or renewal lease period for the fair mar-
ket value or other specified amount at that time.
At December 31, 2012, the estimated future minimum
lease payments (net of noncancelable sublease rentals) under
operating and capital leases, which at inception had a non-
cancelable term of more than one year, were as follows:
At December 31
Current assets
Other assets
Current liabilities
Other liabilities
Total TCO net equity
At December 31
2012
2011
$ 3,251
12,020
2,597
3,390
$ 9,284
$ 3,477
11,619
2,995
3,759
$ 8,342
Year: 2013
2014
2015
2016
2017
Thereafter
Total
Operating
Leases
$ 727
657
618
528
401
617
$ 3,548
Capital
Leases
$ 45
37
23
13
12
59
$ 189
$ (40)
149
(50)
$ 99
Less: Amounts representing interest
and executory costs
Net present values
Less: Capital lease obligations
included in short-term debt
Long-term capital lease obligations
Note 8
Fair Value Measurements
Accounting standards for fair value measurement (ASC 820)
establish a framework for measuring fair value and stipulate
disclosures about fair value measurements. The standards
apply to recurring and nonrecurring fair value measurements
of financial and nonfinancial assets and liabilities. Among
the required disclosures is the fair value hierarchy of inputs
the company uses to value an asset or a liability. The three
levels of the fair value hierarchy are described as follows:
Level 1: Quoted prices (unadjusted) in active markets
for identical assets and liabilities. For the company,
Level 1 inputs include exchange-traded futures con-
tracts for which the parties are willing to transact at the
exchange-quoted price and marketable securities that
are actively traded.
Level 2: Inputs other than Level 1 that are observable,
either directly or indirectly. For the company, Level 2
inputs include quoted prices for similar assets or liabili-
ties, prices obtained through third-party broker quotes
and prices that can be corroborated with other observ-
able inputs for substantially the complete term of a
contract.
Chevron Corporation 2012 Annual Report 41
Note 7
Lease Commitments
Certain noncancelable leases are classified as capital leases,
and the leased assets are included as part of “Properties,
plant and equipment, at cost” on the Consolidated Balance
Sheet. Such leasing arrangements involve crude oil produc-
tion and processing equipment, service stations, bareboat
charters, office buildings, and other facilities. Other leases
are classified as operating leases and are not capitalized.
The payments on operating leases are recorded as expense.
Details of the capitalized leased assets are as follows:
Upstream
Downstream
All Other
Total
Less: Accumulated amortization
Net capitalized leased assets
At December 31
2012
2011
$ 433
316
–
749
479
$ 270
$ 585
316
–
901
568
$ 333
Rental expenses incurred for operating leases during
2012, 2011 and 2010 were as follows:
Minimum rentals
Contingent rentals
Total
Less: Sublease rental income
Net rental expense
Year ended December 31
2012
2011
2010
$ 973
7
980
32
$ 948
$ 892
11
903
39
$ 864
$ 931
10
941
41
$ 900
40 Chevron Corporation 2012 Annual Report
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 8 Fair Value Measurements – Continued
Level 3: Unobservable inputs. The company does not
use Level 3 inputs for any of its recurring fair value
measurements. Level 3 inputs may be required for
the determination of fair value associated with cer-
tain nonrecurring measurements of nonfinancial assets
and liabilities.
The table below shows the fair value hierarchy for assets
and liabilities measured at fair value on a recurring basis at
December 31, 2012, and December 31, 2011.
Marketable Securities The company calculates fair value for
its marketable securities based on quoted market prices for
identical assets and liabilities. The fair values reflect the cash
that would have been received if the instruments were sold at
December 31, 2012.
Derivatives The company records its derivative instru-
ments – other than any commodity derivative contracts that
are designated as normal purchase and normal sale – on the
Consolidated Balance Sheet at fair value, with the offsetting
amount to the Consolidated Statement of Income. For deriv-
atives with identical or similar provisions as contracts that
are publicly traded on a regular basis, the company uses the
market values of the publicly traded instruments as an input
for fair value calculations.
The company’s derivative instruments principally include
futures, swaps, options and forward contracts for crude oil,
Assets and Liabilities Measured at Fair Value on a Recurring Basis
natural gas and refined products. Derivatives classified
as Level 1 include futures, swaps and options contracts
traded in active markets such as the New York Mercantile
Exchange.
Derivatives classified as Level 2 include swaps,
options, and forward contracts principally with financial
institutions and other oil and gas companies, the fair val-
ues of which are obtained from third-party broker quotes,
industry pricing services and exchanges. The company
obtains multiple sources of pricing information for the
Level 2 instruments. Since this pricing information is
generated from observable market data, it has historically
been very consistent. The company does not materi-
ally adjust this information. The company incorporates
internal review, evaluation and assessment procedures,
including a comparison of Level 2 fair values derived from
the company’s internally developed forward curves (on a
sample basis) with the pricing information to document
reasonable, logical and supportable fair value determina-
tions and proper level of classification.
Properties, plant and equipment The company did not
have any material long-lived assets measured at fair value
on a nonrecurring basis to report in 2012 or 2011.
Investments and advances The company did not have
any material investments and advances measured at fair
value on a nonrecurring basis to report in 2012 or 2011.
At December 31, 2012
At December 31, 2011
Total
Level 1
Level 2
Level 3
Marketable securities
Derivatives
Total Assets at Fair Value
Derivatives
Total Liabilities at Fair Value
$ 266
86
$ 352
149
$ 149
$ 266
21
$ 287
148
$ 148
$
–
65
$ 65
1
1
$
$
$
$
–
–
–
–
–
Total
249
208
457
102
102
$
$
$
Level 1
Level 2
Level 3
$
$
$
249
104
353
101
101
$
–
104
$ 104
1
1
$
$
$
$
–
–
–
–
–
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Total
Level 1
Level 2
Level 3
At December 31
Before-Tax
Loss
Year 2012
Total
Level 1
Level 2
Level 3
At December 31
Before-Tax
Loss
Year 2011
Properties, plant and
equipment, net
(held and used)
Properties, plant and
equipment, net
(held for sale)
Investments and advances
Total Nonrecurring
Assets at Fair Value
$ 84
$
16
–
$ 100
$
–
–
–
–
$
$
–
–
–
–
$ 84
$ 213
$ 67
$
16
–
17
15
167
–
$ 100
$ 245
$ 234
$
–
–
–
–
$
–
$ 67
$
81
167
–
–
–
54
108
$ 167
$ 67
$
243
42 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 43
Note 8 Fair Value Measurements – Continued
Assets and Liabilities Not Required to Be Measured at
Fair Value The company holds cash equivalents and bank
time deposits in U.S. and non-U.S. portfolios. The instru-
ments classified as cash equivalents are primarily bank time
deposits with maturities of 90 days or less and money market
funds. “Cash and cash equivalents” had carrying/fair values
of $20,939 and $15,864 at December 31, 2012, and Decem-
ber 31, 2011, respectively. The instruments held in “Time
deposits” are bank time deposits with maturities greater than
90 days, and had carrying/fair values of $708 and $3,958 at
December 31, 2012, and December 31, 2011, respectively.
The fair values of cash, cash equivalents and bank time depos-
its are classified as Level 1 and reflect the cash that would
have been received if the instruments were settled at Decem-
ber 31, 2012.
“Cash and cash equivalents” do not include investments
with a carrying/fair value of $1,454 and $1,240 at December
31, 2012, and December 31, 2011, respectively. At Decem-
ber 31, 2012, these investments are classified as Level 1 and
include restricted funds related to tax payments, upstream
abandonment activities, funds held in escrow for an asset
acquisition and capital investment projects, all of which are
reported in “Deferred charges and other assets” on the Con-
solidated Balance Sheet. Long-term debt of $6,086 and $4,101
at December 31, 2012, and December 31, 2011, had estimated
fair values of $6,770 and $4,928, respectively. Long-term debt
primarily includes corporate issued bonds. The fair value of
corporate bonds is $5,853 and classified as Level 1. The fair
value of the other bonds is $917 and classified as Level 2.
The carrying values of short-term financial assets and
liabilities on the Consolidated Balance Sheet approximate their
fair values. Fair value remeasurements of other financial instru-
ments at December 31, 2012 and 2011, were not material.
The table on the previous page shows the fair value
hierarchy for assets and liabilities measured at fair value on a
nonrecurring basis at December 31, 2012 and 2011.
Note 9
Financial and Derivative Instruments
Derivative Commodity Instruments Chevron is exposed
to market risks related to price volatility of crude oil, refined
products, natural gas, natural gas liquids, liquefied natural gas
and refinery feedstocks.
The company uses derivative commodity instruments to
manage these exposures on a portion of its activity, including
firm commitments and anticipated transactions for the pur-
chase, sale and storage of crude oil, refined products, natural
gas, natural gas liquids and feedstock for company refineries.
From time to time, the company also uses derivative commod-
ity instruments for limited trading purposes.
The company’s derivative commodity instruments princi-
pally include crude oil, natural gas and refined product futures,
swaps, options, and forward contracts. None of the company’s
derivative instruments is designated as a hedging instrument,
although certain of the company’s affiliates make such des-
ignation. The company’s derivatives are not material to the
company’s financial position, results of operations or liquidity.
The company believes it has no material market or credit risks
to its operations, financial position or liquidity as a result of its
commodity derivative activities.
The company uses Inter national Swaps and Derivatives
Association agreements to govern derivative contracts with cer-
tain counterparties to mitigate credit risk. Depending on the
nature of the derivative transactions, bilateral collateral arrange-
ments may also be required. When the company is engaged in
more than one outstanding derivative transaction with the same
counterparty and also has a legally enforceable netting agree-
ment with that counterparty, the net mark-to-market exposure
represents the netting of the positive and negative exposures
with that counterparty and is a reasonable measure of the com-
pany’s credit risk exposure. The company also uses other netting
agreements with certain counterparties with which it conducts
significant transactions to mitigate credit risk.
Derivative instruments measured at fair value at Decem-
ber 31, 2012, December 31, 2011, and December 31, 2010,
and their classification on the Consolidated Balance Sheet and
Consolidated Statement of Income are as follows:
Consolidated Balance Sheet: Fair Value of Derivatives Not
Designated as Hedging Instruments
Balance Sheet
Classification
At December 31 At December 31
2011
2012
Type of Contract
Commodity
Commodity
Accounts and
notes receivable, net
Long-term
receivables, net
Total Assets at Fair Value
Commodity
Commodity
Accounts payable
Deferred credits and other
noncurrent obligations
Total Liabilities at Fair Value
$ 57
29
$ 86
$ 112
37
$ 149
$ 133
75
$ 208
$ 36
66
$ 102
Consolidated Statement of Income: The Effect of Derivatives Not
Designated as Hedging Instruments
Type of Derivative
Contract
Commodity
Commodity
Commodity
Statement of
Income Classification
Gain/(Loss)
Year ended December 31
2012
2011
2010
Sales and other
operating revenues $ (49) $ (255)
Purchased crude oil
and products
Other income
(24)
6
15
(2)
$ (67) $ (242)
$ (98)
(36)
(1)
$ (135)
42 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 43
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 9 Financial and Derivative Instruments – Continued
Concentrations of Credit Risk The company’s financial
instruments that are exposed to concentrations of credit risk
consist primarily of its cash equivalents, time deposits, mar-
ketable securities, derivative financial instruments and trade
receivables. The company’s short-term investments are placed
with a wide array of financial institutions with high credit
ratings. Company investment policies limit the company’s
exposure both to credit risk and to concentrations of credit
risk. Similar policies on diversification and creditworthiness
are applied to the company’s counterparties in derivative
instruments.
The trade receivable balances, reflecting the company’s
diver sified sources of revenue, are dispersed among the
company’s broad customer base worldwide. As a result, the
company believes concentrations of credit risk are limited.
The company routinely assesses the financial strength of its
customers. When the financial strength of a customer is not
considered sufficient, alternative risk mitigation measures may
be deployed including requiring pre-payments, letters of credit
or other acceptable collateral instruments to support sales
to customers.
Note 10
Operating Segments and Geographic Data
Although each subsidiary of Chevron is responsible for its
own affairs, Chevron Corporation manages its investments in
these subsidiaries and their affiliates. The investments are
grouped into two business segments, Upstream and Down-
stream, representing the company’s “reportable segments” and
“operating segments” as defined in accounting standards for
segment reporting (ASC 280). Upstream operations consist
primarily of exploring for, developing and producing crude oil
and natural gas; liquefaction, transportation and regasification
associated with liquefied natural gas (LNG); transporting
crude oil by major international oil export pipelines; process-
ing, transporting, storage and marketing of natural gas; and a
gas-to-liquids project. Downstream operations consist primar-
ily of refining of crude oil into petroleum products; marketing
of crude oil and refined products; transporting of crude oil and
refined products by pipeline, marine vessel, motor equipment
and rail car; and manufacturing and marketing of commodity
petrochemicals, plastics for industrial uses, and fuel and lubri-
cant additives. All Other activities of the company include
mining operations, power generation businesses, worldwide
cash management and debt financing activities, corporate
administrative functions, insurance operations, real estate
activities, energy services, alternative fuels, and technology
companies.
The segments are separately managed for investment purposes
under a structure that includes “segment managers” who report to
the company’s “chief operating decision maker” (CODM) (terms
as defined in ASC 280). The CODM is the company’s Executive
Committee (EXCOM), a committee of senior officers that includes
the Chief Executive Officer, and EXCOM reports to the Board of
Directors of Chevron Corporation.
The operating segments represent components of the
company, as described in accounting standards for segment
reporting (ASC 280), that engage in activities (a) from which
revenues are earned and expenses are incurred; (b) whose
operating results are regularly reviewed by the CODM,
which makes decisions about resources to be allocated to the
segments and assesses their performance; and (c) for which
discrete financial information is available.
44 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 45
Note 10 Operating Segments and Geographic Data – Continued
Segment managers for the reportable segments are
directly accountable to and maintain regular contact with the
company’s CODM to discuss the segment’s operating activities
and financial performance. The CODM approves annual
capital and exploratory budgets at the reportable segment level,
as well as reviews capital and exploratory funding for major
projects and approves major changes to the annual capital and
exploratory budgets. However, business-unit managers within
the operating segments are directly responsible for decisions
relating to project implementation and all other matters con-
nected with daily operations. Company officers who are
members of the EXCOM also have individual management
responsibilities and participate in other committees for pur-
poses other than acting as the CODM.
The company’s primary country of operation is the
United States of America, its country of domicile. Other
components of the company’s operations are reported as
“International” (outside the United States).
Segment Earnings The company evaluates the performance
of its operating segments on an after-tax basis, without con-
sidering the effects of debt financing interest expense or
investment interest income, both of which are managed by the
company on a worldwide basis. Corporate administrative
costs and assets are not allocated to the operating segments.
However, operating segments are billed for the direct use of
corporate services. Nonbillable costs remain at the corporate
level in “All Other.” Earnings by major operating area are
presented in the following table:
Segment Earnings
Upstream
United States
International
Total Upstream
Downstream
United States
International
Total Downstream
Total Segment Earnings
All Other
Interest expense
Interest income
Other
Net Income Attributable
to Chevron Corporation
Year ended December 31
2012
2011
2010
$ 5,332
18,456
23,788
$ 6,512
18,274
24,786
$ 4,122
13,555
17,677
2,048
2,251
4,299
28,087
1,506
2,085
3,591
28,377
1,339
1,139
2,478
20,155
–
83
(1,991)
–
78
(1,560)
(41)
70
(1,160)
$ 26,179
$ 26,895
$ 19,024
Segment Assets Segment assets do not include intercompany
investments or intercompany receivables. Segment assets at
year-end 2012 and 2011 are as follows:
Upstream
United States
International
Goodwill
Total Upstream
Downstream
United States
International
Total Downstream
Total Segment Assets
All Other*
United States
International
Total All Other
Total Assets – United States
Total Assets – International
Goodwill
Total Assets
At December 31
2012
2011
$ 41,891
115,806
4,640
162,337
$ 37,108
98,540
4,642
140,290
23,023
20,024
43,047
205,384
22,182
20,517
42,699
182,989
7,727
19,871
27,598
72,641
155,701
4,640
8,824
17,661
26,485
68,114
136,718
4,642
$ 232,982 $ 209,474
* “All Other” assets consist primarily of worldwide cash, cash equivalents, time
deposits and marketable securities, real estate, energy services, information sys-
tems, mining operations, power generation businesses, alternative fuels, technology
companies, and assets of the corporate administrative functions.
Segment Sales and Other Operating Revenues Operat-
ing segment sales and other operating revenues, including
internal transfers, for the years 2012, 2011 and 2010, are
presented in the table that follows. Products are transferred
between operating segments at internal product values that
approximate market prices.
Revenues for the upstream segment are derived primarily
from the production and sale of crude oil and natural gas,
as well as the sale of third-party production of natural gas.
Revenues for the downstream segment are derived from the
refining and marketing of petroleum products such as gaso-
line, jet fuel, gas oils, lubricants, residual fuel oils and
other products derived from crude oil. This segment also
generates revenues from the manufacture and sale of addi-
tives for fuels and lubricant oils and the transportation and
trading of refined products, crude oil and natural gas liquids.
“All Other” activities include revenues from mining opera-
tions, power generation businesses, insurance operations, real
estate activities, energy services, alternative fuels, and tech-
nology companies.
44 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 45
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 10 Operating Segments and Geographic Data – Continued
Upstream
United States
Intersegment
Total United States
International
Intersegment
Total International
Total Upstream
Downstream
United States
Excise and similar taxes
Intersegment
Total United States
International
Excise and similar taxes
Intersegment
Total International
Total Downstream
All Other
United States
Intersegment
Total United States
International
Intersegment
Total International
Total All Other
Segment Sales and Other
Operating Revenues
United States
International
Total Segment Sales and Other
Operating Revenues
Elimination of intersegment sales
Total Sales and Other
Operating Revenues
Year ended December 31
2012
2011
2010
$ 6,416 $ 9,623 $ 10,316
17,229 18,115
13,839
23,645 27,738
24,155
19,459 20,086
17,300
34,094 35,012
23,834
53,553 55,098
41,134
77,198 82,836
65,289
83,043 86,793
4,665
4,199
49
86
87,757 91,078
113,279 119,254
3,346
3,886
80
81
116,705 123,221
204,462 214,299
70,436
4,484
115
75,035
90,922
4,107
93
95,122
170,157
378
1,300
1,678
4
48
52
1,730
526
1,072
1,598
4
42
46
1,644
610
947
1,557
23
39
62
1,619
113,080 120,414
170,310 178,365
100,747
136,318
283,390 298,779
237,065
(52,800) (54,408) (38,867)
$ 230,590 $ 244,371 $ 198,198
Segment Income Taxes Segment income tax expense for the
years 2012, 2011 and 2010 is as follows:
Upstream
United States
International
Total Upstream
Downstream
United States
International
Total Downstream
All Other
Total Income Tax Expense
Year ended December 31
2012
2011
2010
$ 2,820
16,554
19,374
$ 3,701
16,743
20,444
$ 2,285
10,480
12,765
1,051
587
1,638
(1,016)
785
416
1,201
(1,019)
$ 20,626
$ 19,996
680
462
1,142
(988)
$ 12,919
Note 11
Investments and Advances
Equity in earnings, together with investments in and advances
to companies accounted for using the equity method and other
investments accounted for at or below cost, is shown in the fol-
lowing table. For certain equity affiliates, Chevron pays its share
of some income taxes directly. For such affiliates, the equity in
earnings does not include these taxes, which are reported on the
Consolidated Statement of Income as “Income tax expense.”
Investments and Advances
At December 31
Equity in Earnings
Year ended December 31
2012
2011
2012
2011
2010
Upstream
Tengizchevroil
952
Petropiar
Caspian Pipeline Consortium 1,187
1,261
Petroboscan
3,186
Angola LNG Limited
2,658
Other
Total Upstream
14,695
Downstream
GS Caltex Corporation
Chevron Phillips Chemical
2,610
$ 5,451 $ 5,306 $ 4,614 $ 5,097 $3,398
55
909
262
96
1,094
124
1,032
229
222
2,921
(106)
(21)
266
319
2,420
13,682 5,154 5,706 4,304
116
122
247
(42)
166
2,572
249
248
158
Company LLC
3,451
2,909 1,206
985
704
Star Petroleum Refining
Company Ltd.
Caltex Australia Ltd.
Colonial Pipeline Company
Other
Total Downstream
All Other
Other
Total equity method
Other at or below cost
Total investments and
–
835
–
837
7,733
1,022
819
–
630
22
122
77
101
–
43
196
151
7,952 1,750 1,608 1,279
75
117
–
183
640
54
$ 23,068 $ 22,150 $ 6,889 $ 7,363 $ 5,637
516
49
(15)
650
718
advances
Total United States
Total International
$ 23,718 $ 22,868
$ 5,788 $ 4,847 $ 1,268 $ 1,119 $ 846
$ 17,930 $ 18,021 $ 5,621 $ 6,244 $ 4,791
Descriptions of major affiliates, including significant
differences between the company’s carrying value of its
investments and its underlying equity in the net assets of
the affiliates, are as follows:
Tengizchevroil Chevron has a 50 percent equity ownership
interest in Tengizchevroil (TCO), which was formed in 1993
to develop the Tengiz and Korolev crude oil fields in Kazakh-
Other Segment Information Additional information for
the segmentation of major equity affiliates is contained in
Note 11 below. Information related to proper ties, plant and
equipment by segment is contained in Note 12, on page 48.
46 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 47
Note 11 Investments and Advances – Continued
stan over a 40-year period. At December 31, 2012, the
company’s carrying value of its investment in TCO was about
$170 higher than the amount of underlying equity in TCO’s
net assets. This difference results from Chevron acquiring
a portion of its interest in TCO at a value greater than the
underlying book value for that portion of TCO’s net assets.
See Note 6, on page 41, for summarized financial
informa tion for 100 percent of TCO.
Petropiar Chevron has a 30 percent interest in Petropiar, a
joint stock company formed in 2008 to operate the Hamaca
heavy-oil production and upgrading project. The project,
located in Venezuela’s Orinoco Belt, has a 25-year contract
term. Prior to the formation of Petropiar, Chevron had a 30
percent interest in the Hamaca project. At December 31, 2012,
the company’s carrying value of its investment in Petropiar was
approximately $180 less than the amount of underlying equity
in Petropiar’s net assets. The difference represents the excess of
Chevron’s underlying equity in Petropiar’s net assets over the
net book value of the assets contributed to the venture.
Caspian Pipeline Consortium Chevron has a 15 percent
interest in the Caspian Pipeline Consortium, a variable
interest entity, which provides the critical export route for
crude oil from both TCO and Karachaganak. The company
joined the consortium in 1997 and has investments and
advances totaling $1,187 which includes long-term loans of
$1,179 at year-end 2012. The loans were provided to fund
30 percent of the initial pipeline construction. The company
is not the primary beneficiary of the consortium because it
does not direct activities of the consortium and only receives
its proportionate share of the financial returns.
Petroboscan Chevron has a 39 percent interest in Petro-
boscan, a joint stock company formed in 2006 to operate the
Boscan Field in Venezuela until 2026. Chevron previously
operated the field under an operating service agreement. At
December 31, 2012, the company’s carrying value of its
investment in Petroboscan was approximately $200 higher
than the amount of underlying equity in Petroboscan’s net
assets. The difference reflects the excess of the net book value
of the assets contributed by Chevron over its underlying
equity in Petroboscan’s net assets.
Angola LNG Ltd. Chevron has a 36 percent interest in
Angola LNG Ltd., which will process and liquefy natural gas
produced in Angola for delivery to international markets.
GS Caltex Corporation Chevron owns 50 percent of GS
Caltex Corporation, a joint venture with GS Holdings. The
joint venture imports, refines and markets petroleum prod-
ucts and petrochemicals, predominantly in South Korea.
Chevron Phillips Chemical Company LLC Chevron owns
50 percent of Chevron Phillips Chemical Company LLC.
The other half is owned by Phillips 66.
Star Petroleum Refining Company Ltd. Chevron has a
64 percent ownership interest in Star Petroleum Refining
Company Ltd. (SPRC), which owns the Star Refinery in
Thailand. PTT Public Company Limited owns the remain-
ing 36 percent of SPRC. Due to a change in control effective
June 2012, SPRC is consolidated in Chevron’s Consolidated
Financial Statements.
Caltex Australia Ltd. Chevron has a 50 percent equity
owner ship interest in Caltex Australia Ltd. (CAL). The
remaining 50 percent of CAL is publicly owned. At
December 31, 2012, the fair value of Chevron’s share
of CAL common stock was $2,690.
Other Information “Sales and other operating revenues”
on the Consolidated Statement of Income includes $17,356,
$20,164 and $13,672 with affiliated companies for 2012, 2011
and 2010, respectively. “Purchased crude oil and products”
includes $6,634, $7,489 and $5,559 with affiliated companies
for 2012, 2011 and 2010, respectively.
“Accounts and notes receivable” on the Consolidated
Balance Sheet includes $1,207 and $1,968 due from affiliated
companies at December 31, 2012 and 2011, respectively.
“Accounts payable” includes $407 and $519 due to affiliated
companies at December 31, 2012 and 2011, respectively.
46 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 47
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 11 Investment and Advances – Continued
The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as
Chevron’s total share, which includes Chevron loans to affiliates of $1,494, $957 and $1,543 at December 31, 2012, 2011 and
2010, respectively.
Year ended December 31
Total revenues
Income before income tax expense
Net income attributable to affiliates
At December 31
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Total affiliates’ net equity
Note 12
Properties, Plant and Equipment1
2012
2011
$ 136,065
23,016
16,786
$ 37,541
66,065
27,878
19,366
$ 56,362
$ 140,107
23,054
16,663
$ 35,573
61,855
24,671
19,267
$ 53,490
Affiliates
2010
$ 107,505
18,468
12,831
$ 30,335
57,491
20,428
19,749
$ 47,649
Chevron Share
2012
2011
2010
$ 65,196
9,856
6,938
$ 14,732
23,523
11,093
4,879
$ 22,283
$ 68,632
10,555
7,413
$ 52,088
7,966
5,683
$ 14,695
22,422
11,040
4,491
$ 21,586
$ 12,845
21,401
9,363
4,459
$ 20,424
Gross Investment at Cost
At December 31
Net Investment
Additions at Cost2,3
Depreciation Expense4
Year ended December 31
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
Upstream
United States
International
Total Upstream
Downstream
United States
International
Total Downstream
All Other5
United States
International
Total All Other
Total United States
Total International
Total
$ 81,908 $ 74,369 $ 62,523 $ 37,909 $ 33,461 $ 23,277 $ 8,211 $ 14,404 $ 4,934 $ 3,902 $ 3,870 $ 4,078
14,381 8,015 7,590 7,448
145,799
64,388
19,315 11,917 11,460 11,526
227,707
87,665
110,578
173,101
85,318
123,227
72,543
106,004
125,795
200,164
21,343
29,554
15,722
30,126
21,792
8,990
30,782
20,699
7,422
28,121
19,820
9,697
29,517
11,333
3,930
15,263
10,723
2,995
13,718
10,379
3,948
14,327
1,498
2,544
4,042
1,226
443
1,669
1,199
361
799
741
308
451
1,560 1,107 1,108 1,192
776
332
384
4,959
341
2,496
5
33
4
16
389
4,992
345
2,512
6,392 5,085 4,984 5,160
108,659
36,152
154,822
14,753 8,328 7,927 7,903
68,352
$ 263,481 $ 233,432 $ 207,367 $ 141,348 $ 122,608 $ 104,504 $ 34,015 $ 32,391 $ 21,145 $ 13,413 $ 12,911 $ 13,063
4,722
27
4,749
87,065
120,302
2,845
13
2,858
52,087
89,261
5,117
30
5,147
100,185
133,247
2,872
14
2,886
47,056
75,552
415
4
419
10,124
23,891
591
5
596
16,221
16,170
259
11
270
338
5
343
1 Other than the United States, Nigeria and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2012.
Nigeria had PP&E of $17,485, $15,601 and $13,896 for 2012, 2011 and 2010, respectively. Australia had $21,770 and $12,423 in 2012 and 2011 respectively.
2 Net of dry hole expense related to prior years’ expenditures of $80, $45 and $82 in 2012, 2011 and 2010, respectively.
3 Includes properties acquired with the acquisition of Atlas Energy, Inc., in 2011.
4 Depreciation expense includes accretion expense of $629, $628 and $513 in 2012, 2011 and 2010, respectively.
5 Primarily mining operations, power generation businesses, real estate assets and management information systems.
Note 13
Litigation
MTBE Chevron and many other companies in the petro-
leum industry have used methyl tertiary butyl ether (MTBE)
as a gasoline additive. Chevron is a party to six pending
lawsuits and claims, the majority of which involve numerous
other petroleum marketers and refiners. Resolution of these
lawsuits and claims may ultimately require the company to
correct or ameliorate the alleged effects on the environment
of prior release of MTBE by the company or other parties.
Additional lawsuits and claims related to the use of MTBE,
including personal-injury claims, may be filed in the future.
The company’s ultimate exposure related to pending lawsuits
and claims is not determinable. The company no longer uses
MTBE in the manufacture of gasoline in the United States.
Ecuador Chevron is a defendant in a civil lawsuit before the
Superior Court of Nueva Loja in Lago Agrio, Ecuador,
brought in May 2003 by plaintiffs who claim to be represen-
48 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 49
Note 13 Litigation – Continued
tatives of certain residents of an area where an oil production
consortium formerly had operations. The lawsuit alleges dam-
age to the environment from the oil exploration and
production operations and seeks unspecified damages to fund
environmental remediation and restoration of the alleged
environmental harm, plus a health monitoring program. Until
1992, Texaco Petroleum Company (Texpet), a subsidiary of
Texaco Inc., was a minority member of this consortium with
Petroecuador, the Ecuadorian state-owned oil company, as the
majority partner; since 1990, the operations have been con-
ducted solely by Petroecuador. At the conclusion of the
consortium and following an independent third-party envi-
ronmental audit of the concession area, Texpet entered into a
formal agreement with the Republic of Ecuador and Petroec-
uador for Texpet to remediate specific sites assigned by the
government in proportion to Texpet’s ownership share of the
consortium. Pursuant to that agreement, Texpet conducted a
three-year remediation program at a cost of $40. After certify-
ing that the sites were properly remediated, the government
granted Texpet and all related corporate entities a full release
from any and all environmental liability arising from the con-
sortium operations.
Based on the history described above, Chevron believes
that this lawsuit lacks legal or factual merit. As to mat-
ters of law, the company believes first, that the court lacks
jurisdiction over Chevron; second, that the law under which
plaintiffs bring the action, enacted in 1999, cannot be applied
retroactively; third, that the claims are barred by the statute
of limitations in Ecuador; and, fourth, that the lawsuit is also
barred by the releases from liability previously given to Tex-
pet by the Republic of Ecuador and Petroecuador and by the
pertinent provincial and municipal governments. With regard
to the facts, the company believes that the evidence confirms
that Texpet’s remediation was properly conducted and that
the remaining environmental damage reflects Petroecuador’s
failure to timely fulfill its legal obligations and Petroecuador’s
further conduct since assuming full control over the opera-
tions.
In 2008, a mining engineer appointed by the court to
identify and determine the cause of environmental dam-
age, and to specify steps needed to remediate it, issued a
report recommending that the court assess $18,900, which
would, according to the engineer, provide financial com-
pensation for purported damages, including wrongful death
claims, and pay for, among other items, environmental
remediation, health care systems and additional infrastruc-
ture for Petroecuador. The engineer’s report also asserted
that an additional $8,400 could be assessed against Chevron
for unjust enrichment. In 2009, following the disclosure by
Chevron of evidence that the judge participated in meetings
in which businesspeople and individuals holding themselves
out as government officials discussed the case and its likely
outcome, the judge presiding over the case was recused. In
2010, Chevron moved to strike the mining engineer’s report
and to dismiss the case based on evidence obtained through
discovery in the United States indicating that the report was
prepared by consultants for the plaintiffs before being pre-
sented as the mining engineer’s independent and impartial
work and showing further evidence of misconduct. In August
2010, the judge issued an order stating that he was not bound
by the mining engineer’s report and requiring the parties to
provide their positions on damages within 45 days. Chevron
subsequently petitioned for recusal of the judge, claiming
that he had disregarded evidence of fraud and misconduct
and that he had failed to rule on a number of motions within
the statutory time requirement.
In September 2010, Chevron submitted its position
on damages, asserting that no amount should be assessed
against it. The plaintiffs’ submission, which relied in part on
the mining engineer’s report, took the position that damages
are between approximately $16,000 and $76,000 and that
unjust enrichment should be assessed in an amount between
approximately $5,000 and $38,000. The next day, the judge
issued an order closing the evidentiary phase of the case and
notifying the parties that he had requested the case file so
that he could prepare a judgment. Chevron petitioned to
have that order declared a nullity in light of Chevron’s prior
recusal petition, and because procedural and evidentiary
matters remained unresolved. In October 2010, Chevron’s
motion to recuse the judge was granted. A new judge took
charge of the case and revoked the prior judge’s order closing
the evidentiary phase of the case. On December 17, 2010,
the judge issued an order closing the evidentiary phase of the
case and notifying the parties that he had requested the case
file so that he could prepare a judgment.
On February 14, 2011, the provincial court in Lago
Agrio rendered an adverse judgment in the case. The court
rejected Chevron’s defenses to the extent the court addressed
them in its opinion. The judgment assessed approximately
$8,600 in damages and approximately $900 as an award
for the plaintiffs’ representatives. It also assessed an addi-
tional amount of approximately $8,600 in punitive damages
unless the company issued a public apology within 15 days
of the judgment, which Chevron did not do. On Febru-
ary 17, 2011, the plaintiffs appealed the judgment, seeking
increased damages, and on March 11, 2011, Chevron
appealed the judgment seeking to have the judgment nulli-
fied. On January 3, 2012, an appellate panel in the provincial
court affirmed the February 14, 2011 decision and ordered
that Chevron pay additional attorneys’ fees in the amount
of “0.10% of the values that are derived from the decisional
act of this judgment.” The plaintiffs filed a petition to clarify
48 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 49
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 13 Litigation – Continued
and amplify the appellate decision on January 6, 2012, and
the court issued a ruling in response on January 13, 2012,
purporting to clarify and amplify its January 3, 2012 ruling,
which included clarification that the deadline for the com-
pany to issue a public apology to avoid the additional amount
of approximately $8,600 in punitive damages was within
15 days of the clarification ruling, or February 3, 2012.
Chevron did not issue an apology because doing so might be
mischaracterized as an admission of liability and would be
contrary to facts and evidence submitted at trial. On January
20, 2012, Chevron appealed (called a petition for cassation)
the appellate panel’s decision to Ecuador’s National Court of
Justice. As part of the appeal, Chevron requested the suspen-
sion of any requirement that Chevron post a bond to prevent
enforcement under Ecuadorian law of the judgment during
the cassation appeal. On February 17, 2012, the appellate
panel of the provincial court admitted Chevron’s cassation
appeal in a procedural step necessary for the National Court
of Justice to hear the appeal. The provincial court appel-
late panel denied Chevron’s request for a suspension of the
requirement that Chevron post a bond and stated that it
would not comply with the First and Second Interim Awards
of the international arbitration tribunal discussed below. On
March 29, 2012, the matter was transferred from the provin-
cial court to the National Court of Justice, and on November
22, 2012, the National Court agreed to hear Chevron’s cas-
sation appeal. On August 3, 2012, the provincial court in
Lago Agrio approved a court-appointed liquidator’s report on
damages that calculated the total judgment in the case to be
$19,100.
Chevron has no assets in Ecuador, and the Lago Agrio
plaintiffs’ lawyers have stated in press releases and through
other media that they will seek to enforce the Ecuador-
ian judgment in various countries and otherwise disrupt
Chevron’s operations. On May 30, 2012, the Lago Agrio
plaintiffs filed an action against Chevron Corporation,
Chevron Canada Limited, and Chevron Canada Finance
Limited in the Ontario Superior Court of Justice in Ontario,
Canada, seeking to recognize and enforce the Ecuadorian
judgment. On June 27, 2012, the Lago Agrio plaintiffs filed
an action against Chevron Corporation in the Superior Court
of Justice in Brasilia, Brazil, seeking to recognize and enforce
the Ecuadorian judgment. On October 15, 2012, the provin-
cial court in Lago Agrio issued an ex parte embargo order that
purports to order the seizure of assets belonging to separate
Chevron subsidiaries in Ecuador, Argentina and Colombia.
On November 6, 2012, at the request of the Lago Agrio
plaintiffs, a court in Argentina issued a Freeze Order against
Chevron Argentina S.R.L. and another Chevron subsidiary,
Ingeniero Nortberto Priu, requiring shares of both compa-
nies to be “embargoed,” requiring third parties to withhold
40% of any payments due to Chevron Argentina S.R.L. and
50 Chevron Corporation 2012 Annual Report
ordering banks to withhold 40% of the funds in Chevron
Argentina S.R.L. bank accounts. On December 14th, 2012,
the Argentinean court rejected a motion to revoke the Freeze
Order but modified it by ordering that third parties are not
required to withhold funds but must report their payments.
The court also clarified that the Freeze Order relating to bank
accounts excludes taxes. On January 30, 2013, an appellate
court upheld the Freeze Order. Chevron continues to believe
the provincial court’s judgment is illegitimate and unenforce-
able in Ecuador, the United States and other countries. The
company also believes the judgment is the product of fraud,
and contrary to the legitimate scientific evidence. Chevron
cannot predict the timing or ultimate outcome of the appeals
process in Ecuador or any enforcement action. Chevron
expects to continue a vigorous defense of any imposition of
liability in the Ecuadorian courts and to contest and defend
any and all enforcement actions.
Chevron and Texpet filed an arbitration claim in Sep-
tember 2009 against the Republic of Ecuador before an
arbitral tribunal presiding in the Permanent Court of Arbi-
tration in The Hague under the Rules of the United Nations
Commission on International Trade Law. The claim alleges
violations of the Republic of Ecuador’s obligations under
the United States–Ecuador Bilateral Investment Treaty
(BIT) and breaches of the settlement and release agreements
between the Republic of Ecuador and Texpet (described
above), which are investment agreements protected by the
BIT. Through the arbitration, Chevron and Texpet are
seeking relief against the Republic of Ecuador, including a
declaration that any judgment against Chevron in the Lago
Agrio litigation constitutes a violation of Ecuador’s obliga-
tions under the BIT. On February 9, 2011, the Tribunal
issued an Order for Interim Measures requiring the Republic
of Ecuador to take all measures at its disposal to suspend or
cause to be suspended the enforcement or recognition within
and without Ecuador of any judgment against Chevron in
the Lago Agrio case pending further order of the Tribunal.
On January 25, 2012, the Tribunal converted the Order for
Interim Measures into an Interim Award. Chevron filed a
renewed application for further interim measures on Janu-
ary 4, 2012, and the Republic of Ecuador opposed Chevron’s
application and requested that the existing Order for Interim
Measures be vacated on January 9, 2012. On February 16,
2012, the Tribunal issued a Second Interim Award mandat-
ing that the Republic of Ecuador take all measures necessary
(whether by its judicial, legislative or executive branches) to
suspend or cause to be suspended the enforcement and recog-
nition within and without Ecuador of the judgment against
Chevron and, in particular, to preclude any certification
by the Republic of Ecuador that would cause the judgment
to be enforceable against Chevron. On February 27, 2012,
the Tribunal issued a Third Interim Award confirming its
Chevron Corporation 2012 Annual Report 51
Note 13 Litigation – Continued
jurisdiction to hear Chevron’s arbitration claims. On April 9,
2012, the Tribunal issued a scheduling order to hear issues
relating to the scope of the settlement and release agree-
ments between the Republic of Ecuador and Texpet, and on
July 9, 2012, the Tribunal indicated that it wanted to hear
the remaining issues in January 2014. On February 7, 2013,
the Tribunal issued its Fourth Interim Award in which it
declared that the Republic of Ecuador “has violated the First
and Second Interim Awards under the [BIT], the UNCIT-
RAL Rules and international law in regard to the finalization
and enforcement subject to execution of the Lago Agrio Judg-
ment within and outside Ecuador, including (but not limited
to) Canada, Brazil and Argentina.” A schedule for the Tribu-
nal’s order to show cause hearing will be issued separately.
Through a series of U.S. court proceedings initiated by
Chevron to obtain discovery relating to the Lago Agrio litiga-
tion and the BIT arbitration, Chevron obtained evidence that
it believes shows a pattern of fraud, collusion, corruption, and
other misconduct on the part of several lawyers, consultants
and others acting for the Lago Agrio plaintiffs. In February
2011, Chevron filed a civil lawsuit in the Federal District
Court for the Southern District of New York against the Lago
Agrio plaintiffs and several of their lawyers, consultants and
supporters, alleging violations of the Racketeer Influenced
and Corrupt Organizations Act and other state laws. Through
the civil lawsuit, Chevron is seeking relief that includes
an award of damages and a declaration that any judgment
against Chevron in the Lago Agrio litigation is the result of
fraud and other unlawful conduct and is therefore unenforce-
able. On March 7, 2011, the Federal District Court issued a
preliminary injunction prohibiting the Lago Agrio plaintiffs
and persons acting in concert with them from taking any
action in furtherance of recognition or enforcement of any
judgment against Chevron in the Lago Agrio case pending
resolution of Chevron’s civil lawsuit by the Federal District
Court. On May 31, 2011, the Federal District Court severed
claims one through eight of Chevron’s complaint from the
ninth claim for declaratory relief and imposed a discovery
stay on claims one through eight pending a trial on the ninth
claim for declaratory relief. On September 19, 2011, the U.S.
Court of Appeals for the Second Circuit vacated the prelimi-
nary injunction, stayed the trial on Chevron’s ninth claim, a
claim for declaratory relief, that had been set for November
14, 2011, and denied the defendants’ mandamus petition
to recuse the judge hearing the lawsuit. The Second Circuit
issued its opinion on January 26, 2012 ordering the dismissal
of Chevron’s ninth claim for declaratory relief. On February
16, 2012, the Federal District Court lifted the stay on claims
one through eight, and on October 18, 2012, the Federal Dis-
trict Court set a trial date of October 15, 2013.
The ultimate outcome of the foregoing matters, including
any financial effect on Chevron, remains uncertain. Management
does not believe an estimate of a reasonably possible loss (or a
range of loss) can be made in this case. Due to the defects associ-
ated with the Ecuadorian judgment, the 2008 engineer’s report on
alleged damages and the September 2010 plaintiffs’ submission on
alleged damages, management does not believe these documents
have any utility in calculating a reasonably possible loss (or a range
of loss). Moreover, the highly uncertain legal environment sur-
rounding the case provides no basis for management to estimate a
reasonably possible loss (or a range of loss).
Note 14
Taxes
Income Taxes
Taxes on income
U.S. federal
Current
Deferred
State and local
Current
Deferred
Total United States
International
Current
Deferred
Total International
Total taxes on income
Year ended December 31
2012
2011
2010
$ 1,703
673
$ 1,893
877
$ 1,501
162
652
(145)
2,883
596
41
3,407
376
20
2,059
15,626
1,487
17,113
$ 19,996
16,548
671
17,219
$ 20,626
10,483
377
10,860
$ 12,919
In 2012, before-tax income for U.S. operations, including
related corporate and other charges, was $8,456, compared
with before-tax income of $10,222 and $6,528 in 2011 and
2010, respectively. For international operations, before-tax
income was $37,876, $37,412 and $25,527 in 2012, 2011
and 2010, respectively. U.S. federal income tax expense was
reduced by $165, $191 and $162 in 2012, 2011 and 2010,
respectively, for business tax credits.
The reconciliation between the U.S. statutory federal
income tax rate and the company’s effective income tax rate
is detailed in the following table:
U.S. statutory federal income tax rate
Effect of income taxes from inter-
national operations at rates different
from the U.S. statutory rate
State and local taxes on income, net
of U.S. federal income tax benefit
Prior-year tax adjustments
Tax credits
Effects of changes in tax rates
Other
Effective tax rate
Year ended December 31
2012
35.0%
2011
2010
35.0%
35.0%
7.8
7.5
5.2
0.6
(0.2)
(0.4)
0.3
0.1
43.2%
0.9
(0.1)
(0.4)
0.5
(0.1)
43.3%
0.8
(0.6)
(0.5)
–
0.4
40.3%
50 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 51
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 14 Taxes – Continued
The company’s effective tax rate decreased slightly from
43.3 percent in 2011 to 43.2 percent in 2012. The impact of
lower effective tax rates in international upstream operations
was essentially offset by foreign currency remeasurement
impacts between periods. For international upstream, the
lower effective tax rates in the current period were driven pri-
marily by the effects of asset sales, one-time tax benefits and
reduced withholding taxes, which were partially offset by a
lower utilization of tax credits during the current year.
The company records its deferred taxes on a tax-
jurisdiction basis and classifies those net amounts as current
or noncurrent based on the balance sheet classification of the
related assets or liabilities. The reported deferred tax balances
are composed of the following:
Deferred tax liabilities
Properties, plant and equipment
Investments and other
Total deferred tax liabilities
Deferred tax assets
Foreign tax credits
Abandonment/environmental reserves
Employee benefits
Deferred credits
Tax loss carryforwards
Other accrued liabilities
Inventory
Miscellaneous
Total deferred tax assets
Deferred tax assets valuation allowance
Total deferred taxes, net
At December 31
2012
2011
$ 24,295
2,276
26,571
$ 23,597
2,271
25,868
(10,817)
(5,728)
(5,100)
(2,891)
(738)
(381)
(281)
(1,835)
(8,476)
(5,387)
(4,773)
(1,548)
(828)
(531)
(360)
(1,595)
(27,771) (23,498)
15,443
11,096
$ 14,243
$ 13,466
Deferred tax liabilities at the end of 2012 increased by
approximately $700 from year-end 2011. The increase was
related to increased temporary differences for property, plant
and equipment.
Deferred tax assets increased by approximately $4,300
in 2012. Increases primarily related to additional U.S. foreign
tax credits arising from earnings in high-tax-rate interna-
tional jurisdictions (which were substantially offset by a
valuation allowance) and to future international tax benefits
earned.
The overall valuation allowance relates to deferred tax
assets for U.S. foreign tax credit carryforwards, tax loss carry-
forwards and temporary differences. It reduces the deferred
tax assets to amounts that are, in management’s assessment,
more likely than not to be realized. At the end of 2012, the
company had tax loss carryforwards of approximately $2,009
and tax credit carryforwards of approximately $1,146 primar-
ily related to various international tax jurisdictions. Whereas
some of these tax loss carryforwards do not have an expira-
tion date, others expire at various times from 2013 through
2029. U.S. foreign tax credit carryforwards of $10,817 will
expire between 2013 and 2022.
At December 31, 2012 and 2011, deferred taxes were
classified on the Consolidated Balance Sheet as follows:
Prepaid expenses and other current assets
Deferred charges and other assets
Federal and other taxes on income
Noncurrent deferred income taxes
Total deferred income taxes, net
At December 31
2012
2011
$ (1,365) $ (1,149)
(2,662)
(1,224)
295
15,544
598
17,672
$ 14,243
$ 13,466
Income taxes are not accrued for unremitted earnings
of international operations that have been or are intended
to be reinvested indefinitely. Undistributed earnings of inter-
national consolidated subsidiaries and affiliates for which
no deferred income tax provision has been made for possible
future remittances totaled $26,527 at December 31, 2012.
This amount represents earnings reinvested as part of the
company’s ongoing international business. It is not practicable
to estimate the amount of taxes that might be payable on
the possible remittance of earnings that are intended to be
reinvested indefinitely. At the end of 2012, deferred income
taxes were recorded for the undistributed earnings of certain
international operations where indefinite reinvestment of the
earnings is not planned. The company does not anticipate
incurring significant additional taxes on remittances of earn-
ings that are not indefinitely reinvested.
Uncertain Income Tax Positions Under accounting stan-
dards for uncertainty in income taxes (ASC 740-10), a
company recognizes a tax benefit in the financial statements
for an uncertain tax position only if management’s assess-
ment is that the position is “more likely than not” (i.e., a
likelihood greater than 50 percent) to be allowed by the tax
jurisdiction based solely on the technical merits of the posi-
tion. The term “tax position” in the accounting standards for
income taxes refers to a position in a previously filed tax
return or a position expected to be taken in a future tax
return that is reflected in measuring current or deferred
income tax assets and liabilities for interim or annual periods.
The following table indicates the changes to the compa-
ny’s unrecognized tax benefits for the years ended December
31, 2012, 2011 and 2010. The term “unrecognized tax ben-
efits” in the accounting standards for income taxes refers to
the differences between a tax position taken or expected to be
taken in a tax return and the benefit measured and recognized
in the financial statements. Interest and penalties are not
included.
52 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 53
Note 14 Taxes – Continued
2012
2011
2010
Balance at January 1
Foreign currency effects
Additions based on tax positions
taken in current year
Additions/reductions resulting from
current-year asset acquisitions/sales
Additions for tax positions taken
in prior years
Reductions for tax positions taken
in prior years
Settlements with taxing authorities
in current year
Reductions as a result of a lapse
of the applicable statute of limitations
Balance at December 31
$ 3,481
4
$ 3,507
(2)
$ 3,195
17
543
469
334
–
(41)
–
152
236
270
(899)
(366)
(165)
(138)
(318)
(136)
(72)
(4)
$ 3,481
$ 3,071
(8)
$ 3,507
The decrease in unrecognized tax benefits between
December 31, 2011, and December 31, 2012 was primarily
due to new information received during the fourth quarter
2012 regarding the sustainability of certain U.S. foreign tax
credits. The reduction in unrecognized tax benefits related to
these foreign tax credits had no impact on the effective tax
rate since the deferred tax asset recognized for these foreign
tax credits has been offset with a full valuation allowance.
Approximately 67 percent of the $3,071 of unrecog-
nized tax benefits at December 31, 2012, would have an
impact on the effective tax rate if subsequently recognized.
Certain of these unrecognized tax benefits relate to tax
carryforwards that may require a full valuation allowance
at the time of any such recognition.
Tax positions for Chevron and its subsidiaries and
affiliates are subject to income tax audits by many tax juris-
dictions throughout the world. For the company’s major tax
jurisdictions, examinations of tax returns for certain prior tax years
had not been completed as of December 31, 2012. For these
jurisdictions, the latest years for which income tax examinations
had been finalized were as follows: United States – 2007,
Nigeria – 2000, Angola – 2001, Saudi Arabia – 2003 and
Kazakhstan – 2006.
The company engages in ongoing discussions with tax
authorities regarding the resolution of tax matters in the various
jurisdictions. Both the outcome of these tax matters and the
timing of resolution and/or closure of the tax audits are highly
uncertain. However, it is reasonably possible that developments
on tax matters in certain tax jurisdictions may result in signifi-
cant increases or decreases in the company’s total unrecognized
tax benefits within the next 12 months. Given the number of
years that still remain subject to examination and the number
of matters being examined in the various tax jurisdictions, the
company is unable to estimate the range of possible adjust-
ments to the balance of unrecognized tax benefits.
The company is currently assessing the potential impact of
an August 2012 decision by the U.S. Court of Appeals for the
Third Circuit that disallows the Historic Rehabilitation Tax
Credits (HRTCs) claimed by an unrelated taxpayer. The com-
pany has claimed a significant amount of HRTCs on its U.S.
federal income tax returns in open years, and it is reasonably
possible that the specific findings from management’s ongoing
assessment and evaluation could result in a significant increase
in the company’s unrecognized tax benefit within the next 12
months. Any such increase would impact the effective tax rate.
On the Consolidated Statement of Income, the company
reports interest and penalties related to liabilities for uncertain
tax positions as “Income tax expense.” As of December 31,
2012, accruals of $293 for anticipated interest and penalty
obligations were included on the Consolidated Balance Sheet,
compared with accruals of $118 as of year-end 2011. Income
tax expense (benefit) associated with interest and penalties was
$145, $(64) and $40 in 2012, 2011 and 2010, respectively.
Taxes Other Than on Income
United States
Excise and similar taxes on
products and merchandise
Import duties and other levies
Property and other
miscellaneous taxes
Payroll taxes
Taxes on production
Total United States
International
Excise and similar taxes on
products and merchandise
Import duties and other levies
Property and other
miscellaneous taxes
Payroll taxes
Taxes on production
Total International
Total taxes other than on income
Year ended December 31
2012
2011
2010
$ 4,665
1
$ 4,199
4
$ 4,484
–
782
240
328
6,016
726
236
308
5,473
567
219
271
5,541
3,345
106
3,886
3,511
4,107
6,183
2,501
160
248
6,360
$ 12,376
2,354
148
256
10,155
$ 15,628
2,000
133
227
12,650
$ 18,191
52 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 53
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 15
Short-Term Debt
Commercial paper*
Notes payable to banks and others with
originating terms of one year or less
Current maturities of long-term debt
Current maturities of long-term
capital leases
Redeemable long-term obligations
Long-term debt
Capital leases
Subtotal
Reclassified to long-term debt
Total short-term debt
At December 31
2012
2011
$ 2,783
$ 2,498
23
20
38
40
17
54
3,151
12
6,027
(5,900)
$ 127
3,317
14
5,940
(5,600)
$ 340
* Weighted-average interest rates at December 31, 2012 and 2011, were 0.13 percent
and 0.04 percent, respectively.
Redeemable long-term obligations consist primarily of tax-
exempt variable-rate put bonds that are included as current
liabilities because they become redeemable at the option of the
bondholders during the year following the balance sheet date.
The company may periodically enter into interest rate
swaps on a portion of its short-term debt. At December 31,
2012, the company had no interest rate swaps on short-
term debt.
At December 31, 2012, the company had $6,000 in
committed credit facilities with various major banks, expiring
in December 2016, that enable the refinancing of short-term
obligations on a long-term basis. These facilities support com-
mercial paper borrowing and can also be used for general
corporate purposes. The company’s practice has been to
continually replace expiring commitments with new commit-
ments on substantially the same terms, maintaining levels
management believes appropriate. Any borrowings under the
facilities would be unsecured indebtedness at interest rates
based on the London Interbank Offered Rate or an average of
base lending rates published by specified banks and on terms
reflecting the company’s strong credit rating. No borrowings
were outstanding under these facilities at December 31, 2012.
At December 31, 2012 and 2011, the company classified
$5,900 and $5,600, respectively, of short-term debt as long-
term. Settlement of these obligations is not expected to require
the use of working capital within one year, as the company has
both the intent and the ability, as evidenced by committed
credit facilities, to refinance them on a long-term basis.
Note 16
Long-Term Debt
Total long-term debt, excluding capital leases, at December 31,
2012, was $11,966. The company’s long-term debt
outstanding at year-end 2012 and 2011 was as follows:
At December 31
2012
2011
3.95% notes due 2014
1.104% notes due 2017
2.355% notes due 2022
4.95% notes due 2019
8.625% debentures due 2032
8.625% debentures due 2031
7.5% debentures due 2043
8% debentures due 2032
9.75% debentures due 2020
7.327% amortizing notes due 20141
8.875% debentures due 2021
Medium-term notes, maturing from
2021 to 2038 (5.92%)2
Other long-term debt (8.07%)2
Total including debt due within one year
Debt due within one year
Reclassified from short-term debt
Total long-term debt
$
–
2,000
2,000
1,500
147
107
83
74
54
43
40
38
–
6,086
5,900
$ 11,966
$ 1,998
–
–
1,500
147
107
83
74
54
59
40
38
1
4,101
(17)
5,600
$ 9,684
(20)
1 Guarantee of ESOP debt.
2 Weighted-average interest rate at December 31, 2012 and 2011.
In November 2012, the company filed with the SEC an
automatic registration statement that expires in 2015. This regis-
tration statement is for an unspecified amount of nonconvertible
debt securities issued or guaranteed by the company.
Long-term debt of $6,086 matures as follows: 2013 – $20;
2014– $23; 2015 – $0; 2016 – $0; 2017 – $2,000; and after
2017 – $4,043.
In December 2012, $4,000 of Chevron Corporation
bonds were issued and $2,000 of Chevron Corporation
3.95% bonds due 2014 were redeemed early.
See Note 8, beginning on page 41, for information
concerning the fair value of the company’s long-term debt.
54 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 55
Note 17
New Accounting Standards
Balance Sheet (Topic 210) Disclosures about Offsetting
Assets and Liabilities (ASU 2011-11) In December 2011,
the FASB issued ASU 2011-11, which became effective for
the company on January 1, 2013. The standard amends and
expands disclosure requirements about offsetting and related
arrangements. The company does not anticipate any impacts
to its results of operations, financial position or liquidity
when the guidance becomes effective.
Comprehensive Income (Topic 220) Reporting of
Amounts Reclassified Out of Accumulated Other Com-
prehensive Income (ASU 2013-02) The FASB issued ASU
2013-02 in February 2013. This standard became effective
for the company on January 1, 2013. ASU 2013-02 changes
the presentation requirements of significant reclassifications
out of accumulated other comprehensive income in their
entirety and their corresponding effect on net income. For
other significant amounts that are not required to be reclas-
sified in their entirety, the standard requires the company to
cross-reference to related footnote disclosures. Adoption of
the standard is not expected to have a significant impact on
the company’s financial statement presentation.
Note 18
Accounting for Suspended Exploratory Wells
Accounting standards for the costs of exploratory wells (ASC
932) provide that exploratory well costs continue to be capi-
talized after the completion of drilling when (a) the well has
found a sufficient quantity of reserves to justify completion
as a producing well, and (b) the entity is making sufficient
progress assessing the reserves and the economic and operat-
ing viability of the project. If either condition is not met or
if an enterprise obtains information that raises substantial
doubt about the economic or operational viability of the proj-
ect, the exploratory well would be assumed to be impaired,
and its costs, net of any salvage value, would be charged to
expense. (Note that an entity is not required to complete the
exploratory well as a producing well.) The accounting stan-
dards provide a number of indicators that can assist an entity
in demonstrating that sufficient progress is being made in
assessing the reserves and economic viability of the project.
The following table indicates the changes to the company’s
suspended exploratory well costs for the three years ended
December 31, 2012:
Beginning balance at January 1
Additions to capitalized exploratory
well costs pending the
determination of proved reserves
Reclassifications to wells, facilities
and equipment based on the
determination of proved reserves
Capitalized exploratory well costs
charged to expense
Other reductions*
Ending balance at December 31
*Represents property sales.
2012
2011
2010
$ 2,434
$ 2,718
$ 2,435
595
652
482
(244)
(828)
(129)
(49)
(55)
(45)
(63)
$ 2,434
$ 2,681
(70)
–
$ 2,718
The following table provides an aging of capitalized well
costs and the number of projects for which exploratory well
costs have been capitalized for a period greater than one year
since the completion of drilling.
Exploratory well costs capitalized
for a period of one year or less
Exploratory well costs capitalized
for a period greater than one year
Balance at December 31
Number of projects with exploratory
well costs that have been capitalized
for a period greater than one year*
At December 31
2012
2011
2010
$ 501
$ 557
$ 419
2,180
$ 2,681
1,877
$ 2,434
2,299
$ 2,718
46
47
53
* Certain projects have multiple wells or fields or both.
Of the $2,180 of exploratory well costs capitalized for
more than one year at December 31, 2012, $1,359 (23 proj-
ects) is related to projects that had drilling activities under
way or firmly planned for the near future. The $821 balance
is related to 23 projects in areas requiring a major capital
expenditure before production could begin and for which
additional drilling efforts were not under way or firmly
planned for the near future. Additional drilling was not
deemed necessary because the presence of hydrocarbons had
already been established, and other activities were in process
to enable a future decision on project development.
54 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 55
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 18 Accounting for Suspended Exploratory Wells – Continued
The projects for the $821 referenced above had the fol-
lowing activities associated with assessing the reserves and the
projects’ economic viability: (a) $359 (six projects) – undergo-
ing front-end engineering and design with final investment
decision expected within three years; (b) $218 (four projects)
– development concept under review by government; (c) $202
(five projects) – development alternatives under review; (d)
$42 (eight projects) – miscellaneous activities for projects with
smaller amounts suspended. While progress was being made
on all 46 projects, the decision on the recognition of proved
reserves under SEC rules in some cases may not occur for
several years because of the complexity, scale and negotiations
connected with the projects. However, the majority of these
decisions are expected to occur in the next three years.
The $2,180 of suspended well costs capitalized for a
period greater than one year as of December 31, 2012, repre-
sents 166 exploratory wells in 46 projects. The tables below
contain the aging of these costs on a well and project basis:
Aging based on drilling completion date of individual wells:
1997–2001
2002–2006
2007–2011
Total
Aging based on drilling completion date of last
suspended well in project:
1999
2003–2007
2008–2012
Total
Amount
$
65
416
1,699
$ 2,180
Amount
$
8
322
1,850
$ 2,180
Number
of wells
23
41
102
166
Number
of projects
1
8
37
46
Note 19
Stock Options and Other Share-Based Compensation
Compensation expense for stock options for 2012, 2011 and
2010 was $283 ($184 after tax), $265 ($172 after tax) and
$229 ($149 after tax), respectively. In addition, compensa-
tion expense for stock appreciation rights, restricted stock,
performance units and restricted stock units was $177 ($115
after tax), $214 ($139 after tax) and $194 ($126 after tax) for
2012, 2011 and 2010, respectively. No significant stock-based
compensation cost was capitalized at December 31, 2012,
or December 31, 2011.
Cash received in payment for option exercises under all
share-based payment arrangements for 2012, 2011 and 2010
was $753, $948 and $385, respectively. Actual tax benefits
realized for the tax deductions from option exercises were
$101, $121 and $66 for 2012, 2011 and 2010, respectively.
Cash paid to settle performance units and stock appre-
ciation rights was $123, $151 and $140 for 2012, 2011 and
2010, respectively.
Chevron Long-Term Incentive Plan (LTIP) Awards under
the LTIP may take the form of, but are not limited to, stock
options, restricted stock, restricted stock units, stock appreci-
ation rights, performance units and nonstock grants. From
April 2004 through January 2014, no more than 160 million
shares may be issued under the LTIP, and no more than
64 million of those shares may be in a form other than a stock
option, stock appreciation right or award requiring full payment
for shares by the award recipient. For the major types of awards
outstanding as of December 31, 2012, the contractual terms
vary between three years for the performance units and 10 years
for the stock options and stock appreciation rights.
Unocal Share-Based Plans (Unocal Plans) When Chevron
acquired Unocal in August 2005, outstanding stock options
and stock appreciation rights granted under various Unocal
Plans were exchanged for fully vested Chevron options and
appreciation rights. These awards retained the same provi-
sions as the original Unocal Plans. Unexercised awards began
expiring in early 2010 and will continue to expire through
early 2015.
56 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 57
Note 19 Stock Options and Other Share-Based Compensation – Continued
The fair market values of stock options and stock appre-
ciation rights granted in 2012, 2011 and 2010 were measured
on the date of grant using the Black-Scholes option-pricing
model, with the following weighted-average assumptions:
Stock Options
Expected term in years1
Volatility2
Risk-free interest rate based on
zero coupon U.S. treasury note
Dividend yield
Weighted-average fair value per
Year ended December 31
2012
2011
2010
6.0
31.7%
6.2
31.0%
6.1
30.8%
1.1%
3.2%
2.6%
3.6%
2.9%
3.9%
option granted
$ 23.35
$ 21.24
$ 16.28
1 Expected term is based on historical exercise and postvesting cancellation data.
2 Volatility rate is based on historical stock prices over an appropriate period,
generally equal to the expected term.
A summary of option activity during 2012 is presented
below:
Weighted-
Average
Exercise
Price
Shares
(Thousands)
Average
Remaining
Contractual
Term (Years)
Aggregate
Intrinsic
Value
Outstanding at
January 1, 2012
Granted
Exercised
Forfeited
Outstanding at
December 31, 2012
Exercisable at
December 31, 2012
72,348
12,455
(12,024)
(884)
$ 73.71
$ 107.73
$ 62.13
$ 96.78
71,895
$ 81.26
6.3
$ 1,933
47,060
$ 72.82
5.2
$ 1,662
The total intrinsic value (i.e., the difference between the
exercise price and the market price) of options exercised during
2012, 2011 and 2010 was $580, $668 and $259, respectively.
During this period, the company continued its practice of
issuing treasury shares upon exercise of these awards.
As of December 31, 2012, there was $255 of total unrec-
ognized before-tax compensation cost related to nonvested
share-based compensation arrangements granted under the
plans. That cost is expected to be recognized over a weighted-
average period of 1.7 years.
At January 1, 2012, the number of LTIP performance
units outstanding was equivalent to 2,881,836 shares. During
2012, 888,350 units were granted, 882,003 units vested with
cash proceeds distributed to recipients and 60,426 units
were forfeited. At December 31, 2012, units outstanding
were 2,827,757, and the fair value of the liability recorded
for these instruments was $320. In addition, outstanding
stock appreciation rights and other awards that were
granted under various LTIP and former Unocal programs
totaled approximately 2.4 million equivalent shares as of
December 31, 2012. A liability of $71 was recorded for
these awards.
Note 20
Employee Benefit Plans
The company has defined benefit pension plans for many
employees. The company typically prefunds defined ben-
efit plans as required by local regulations or in certain
situations where prefunding provides economic advan-
tages. In the United States, all qualified plans are subject
to the Employee Retirement Income Security Act (ERISA)
minimum funding standard. The company does not typi-
cally fund U.S. nonqualified pension plans that are not
subject to funding requirements under laws and regula-
tions because contributions to these pension plans may be
less economic and investment returns may be less attractive
than the company’s other investment alternatives.
The company also sponsors other postretirement
(OPEB) plans that provide medical and dental benefits, as
well as life insurance for some active and qualifying retired
employees. The plans are unfunded, and the company and
retirees share the costs. Medical coverage for Medicare-
eligible retirees in the company’s main U.S. medical plan
is secondary to Medicare (including Part D) and the
increase to the company contribution for retiree medical
coverage is limited to no more than 4 percent each year.
Certain life insurance benefits are paid by the company.
Under accounting standards for postretirement bene-
fits (ASC 715), the company recognizes the overfunded or
underfunded status of each of its defined benefit pension
and OPEB plans as an asset or liability on the Consoli-
dated Balance Sheet.
56 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 57
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 20 Employee Benefit Plans – Continued
The funded status of the company’s pension and other postretirement benefit plans for 2012 and 2011 follows:
Pension Benefits
U.S.
2012
Int’l.
U.S.
2011
Int’l.
Other Benefits
2012
2011
Change in Benefit Obligation
Benefit obligation at January 1
Service cost
Interest cost
Plan participants’ contributions
Plan amendments
Actuarial loss (gain)
Foreign currency exchange rate changes
Benefits paid
Divestitures
Curtailment
Benefit obligation at December 31
Change in Plan Assets
Fair value of plan assets at January 1
Actual return on plan assets
Foreign currency exchange rate changes
Employer contributions
Plan participants’ contributions
Benefits paid
Divestitures
Fair value of plan assets at December 31
Funded Status at December 31
$ 12,165 $ 5,519 $ 10,271
374
463
–
–
1,920
–
(863)
–
–
12,165
181
320
7
37
417
114
(308)
–
–
6,287
452
435
–
94
1,322
–
(763)
(51)
–
13,654
$ 5,070
174
325
6
27
318
(98)
(303)
–
–
5,519
8,720
3,503
1,149
118
–
(66)
844
319
–
6
(763)
(303)
(41)
–
9,909
3,577
$ (3,745) $ (2,162) $ (3,445) $ (1,942)
3,577
375
90
384
7
(308)
–
4,125
8,579
(143)
–
1,147
–
(863)
–
8,720
$ 3,765 $ 3,605
61
58
153
180
151
148
11
–
44
149
1
(19)
(350)
(346)
(49)
–
–
(10)
3,787 3,765
–
–
–
–
–
–
199
198
151
148
(350)
(346)
–
–
–
–
$ (3,787) $ (3,765)
Amounts recognized on the Consolidated Balance Sheet for the company’s pension and other postretirement benefit plans at
December 31, 2012 and 2011, include:
Pension Benefits
Deferred charges and other assets
Accrued liabilities
Reserves for employee benefit plans
Net amount recognized at December 31
2012
$
U.S.
Int’l.
7 $
U.S.
5
(61)
(72)
(3,691)
(2,141) (3,378)
$ (3,745) $ (2,162) $ (3,445)
55 $
(76)
2011
Int’l.
$ 116
(84)
(1,974)
$ (1,942)
Other Benefits
$
2012
– $
(225)
2011
–
(222)
(3,562) (3,543)
$ (3,787) $ (3,765)
Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB
plans were $9,742 and $9,279 at the end of 2012 and 2011, respectively. These amounts consisted of:
Pension Benefits
Net actuarial loss
Prior service (credit) costs
Total recognized at December 31
2012
U.S.
Int’l.
U.S.
$ 6,087 $ 2,439 $ 5,982
(44)
$ 6,145 $ 2,609 $ 5,938
170
58
2011
Int’l.
$ 2,250
152
$ 2,402
Other Benefits
2012
2011
968 $ 1,002
20
(63)
988 $
939
$
$
The accumulated benefit obligations for all U.S. and international pension plans were $12,108 and $5,167, respectively, at
December 31, 2012, and $11,198 and $4,518, respectively, at December 31, 2011.
58 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 59
Note 20 Employee Benefit Plans – Continued
Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at
December 31, 2012 and 2011, was:
2012
Pension Benefits
2011
U.S.
Int’l.
U.S.
Int’l.
Projected benefit obligations
Accumulated benefit obligations
Fair value of plan assets
$ 13,647 $ 4,812
4,063
12,101
2,756
9,895
$ 12,157 $ 4,207
3,586
11,191
2,357
8,707
The components of net periodic benefit cost and amounts recognized in other comprehensive income for 2012, 2011 and
2010 are shown in the table below:
Net Periodic Benefit Cost
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service
(credits) costs
Recognized actuarial losses
Settlement losses
Curtailment losses (gains)
Total net periodic benefit cost
Changes Recognized in Other
Comprehensive Income
Net actuarial loss during period
Amortization of actuarial loss
Prior service cost during period
Amortization of prior service
credits (costs)
Total changes recognized in
other comprehensive income
Recognized in Net Periodic
Benefit Cost and Other
Comprehensive Income
Pension Benefits
2012
Int’l.
U.S.
2011
Int’l.
U.S.
$ 181
320
(269)
$ 374
463
(613)
$ 174
325
(283)
$ 337
486
(538)
18
136
5
–
391
(8)
310
298
–
824
19
101
–
35
371
(8)
318
186
–
781
2010
Int’l.
$ 153
307
(241)
22
98
6
–
345
U.S.
$ 452
435
(634)
(7)
470
220
–
936
Other Benefits
2012
2011
2010
$ 61
153
–
$ 58
180
–
(72)
56
(26)
–
172
(72)
64
–
(10)
220
$ 39
175
–
(75)
27
–
–
166
805
(700)
94
330
(141)
37
2,671
(608)
–
448
(101)
27
242
(504)
–
118
(104)
–
45
(79)
11
131
(64)
–
497
(27)
12
7
(18)
8
(54)
8
(22)
72
72
75
206
208
2,071
320
(254)
(8)
49
139
557
$ 1,142
$ 599
$ 2,895
$ 691
$ 527
$ 337
$ 221
$ 359
$ 723
Net actuarial losses recorded in “Accumulated other
comprehensive loss” at December 31, 2012, for the compa-
ny’s U.S. pension, international pension and OPEB plans are
being amortized on a straight-line basis over approximately
10, 13 and 10 years, respectively. These amortization periods
represent the estimated average remaining service of employ-
ees expected to receive benefits under the plans. These losses
are amortized to the extent they exceed 10 percent of the
higher of the projected benefit obligation or market-related
value of plan assets. The amount subject to amortization is
determined on a plan-by-plan basis. During 2013, the com-
pany estimates actuarial losses of $472, $143 and $54 will be
amortized from “Accumulated other comprehensive loss” for
U.S. pension, international pension and OPEB plans, respec-
tively. In addition, the company estimates an additional
$230 will be recognized from “Accumulated other compre-
hensive loss” during 2013 related to lump-sum settlement
costs from U.S. pension plans.
The weighted average amortization period for recognizing
prior service costs (credits) recorded in “Accumulated other
comprehensive loss” at December 31, 2012, was approximately
10 and 13 years for U.S. and international pension plans,
respectively, and 11 years for other postretirement benefit
plans. During 2013, the company estimates prior service
(credits) costs of $1, $22 and $(50) will be amortized from
“Accumulated other comprehensive loss” for U.S. pension,
international pension and OPEB plans, respectively.
58 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 59
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 20 Employee Benefit Plans – Continued
Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit
costs for years ended December 31:
U.S.
2012
Int’l.
U.S.
2011
Int’l.
Pension Benefits
U.S.
2010
Int’l.
Other Benefits
2012
2011
2010
Assumptions used to determine
benefit obligations:
Discount rate
Rate of compensation increase
Assumptions used to determine
net periodic benefit cost:
Discount rate
Expected return on plan assets
Rate of compensation increase
3.6%
4.5%
5.2%
5.5%
3.8%
4.5%
5.9%
5.7%
4.8%
4.5%
6.5%
6.7%
4.1%
N/A
4.2%
N/A
5.2%
N/A
3.8%
7.5%
4.5%
5.9%
7.5%
5.7%
4.8%
7.8%
4.5%
6.5%
7.8%
6.7%
5.3%
7.8%
4.5%
6.8%
7.8%
6.3%
4.2%
N/A
N/A
5.2%
N/A
N/A
5.9%
N/A
N/A
Expected Return on Plan Assets The company’s estimated
long-term rates of return on pension assets are driven pri-
marily by actual historical asset-class returns, an assessment
of expected future performance, advice from external actu-
arial firms and the incorporation of specific asset-class risk
factors. Asset allocations are periodically updated using pen-
sion plan asset/liability studies, and the company’s estimated
long-term rates of return are consistent with these studies.
For 2012, the company used an expected long-term rate
of return of 7.5 percent for U.S. pension plan assets, which
account for 70 percent of the company’s pension plan assets.
In 2011 and 2010, the company used a long-term rate of
return of 7.8 percent for this plan.
The market-related value of assets of the major U.S.
pension plan used in the determination of pension expense
was based on the market values in the three months preced-
ing the year-end measurement date. Management considers
the three-month time period long enough to minimize the
effects of distortions from day-to-day market volatility and
still be contemporaneous to the end of the year. For other
plans, market value of assets as of year-end is used in calcu-
lating the pension expense.
Discount Rate The discount rate assumptions used to
determine the U.S. and international pension and postretire-
ment benefit plan obligations and expense reflect the rate
at which benefits could be effectively settled and is equal to
the equivalent single rate resulting from yield curve analysis.
This analysis considered the projected benefit payments spe-
cific to the company’s plans and the yields on high-quality
bonds. At December 31, 2012, the company used a 3.6 per-
cent discount rate for the U.S. pension plans and 3.9 percent
for the main U.S. OPEB plan. The discount rates at the end
of 2011 and 2010 were 3.8 and 4.0 percent and 4.8 and 5.0
percent for the U.S. pension plans and the main U.S. OPEB
plans, respectively.
Other Benefit Assumptions For the measurement of accu-
mulated postretirement benefit obligation at December 31,
2012, for the main U.S. postretirement medical plan, the
assumed health care cost-trend rates start with 7.5 percent
in 2013 and gradually decline to 4.5 percent for 2025 and
beyond. For this measurement at December 31, 2011, the
assumed health care cost-trend rates started with 8 percent
in 2012 and gradually declined to 5 percent for 2023 and
beyond. In both measurements, the annual increase to com-
pany contributions was capped at 4 percent.
Assumed health care cost-trend rates can have a signifi-
cant effect on the amounts reported for retiree health care
costs. The impact is mitigated by the 4 percent cap on the
company’s medical contributions for the primary U.S. plan.
A 1-percentage-point change in the assumed health care cost-
trend rates would have the following effects:
Effect on total service and interest cost components
Effect on postretirement benefit obligation
$ 16
$ 165
$ (13)
$ (141)
1 Percent
Increase
1 Percent
Decrease
Plan Assets and Investment Strategy The fair value hierar-
chy of inputs the company uses to value the pension assets is
divided into three levels:
Level 1: Fair values of these assets are measured using
unadjusted quoted prices for the assets or the prices of identical
assets in active markets that the plans have the ability to access.
Level 2: Fair values of these assets are measured based on
quoted prices for similar assets in active markets; quoted prices
for identical or similar assets in inactive markets; inputs other
than quoted prices that are observable for the asset; and inputs
60 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 61
Note 20 Employee Benefit Plans – Continued
that are derived principally from or corroborated by observ-
able market data through correlation or other means. If the
asset has a contractual term, the Level 2 input is observable
for substantially the full term of the asset. The fair values for
Level 2 assets are generally obtained from third-party broker
quotes, independent pricing services and exchanges.
Level 3: Inputs to the fair value measurement are
unobservable for these assets. Valuation may be performed
using a financial model with estimated inputs entered into
the model.
The fair value measurements of the company’s pen-
sion plans for 2012 and 2011 are below:
At December 31, 2011
Equities
U.S.1
International
Collective Trusts/Mutual Funds2
Fixed Income
Government
Corporate
Mortgage-Backed Securities
Other Asset Backed
Collective Trusts/Mutual Funds2
Mixed Funds3
Real Estate4
Cash and Cash Equivalents
Other5
Total at December 31, 2011
At December 31, 2012
Equities
U.S.1
International
Collective Trusts/Mutual Funds2
Fixed Income
Government
Corporate
Mortgage-Backed Securities
Other Asset Backed
Collective Trusts/Mutual Funds2
Mixed Funds3
Real Estate4
Cash and Cash Equivalents
Other5
Total at December 31, 2012
Total Fair Value
Level 1
Level 2
Level 3 Total Fair Value
Level 1
Level 2
Level 3
U.S.
Int’l.
$ 1,470
1,203
2,633
622
338
107
61
1,046
10
843
404
(17)
$ 8,720
$ 1,709
1,263
2,979
435
384
65
51
1,520
–
1,114
373
16
$ 9,909
$ 1,470
1,203
14
146
–
–
–
–
10
–
404
(79)
$ 3,168
$ 1,709
1,263
7
396
–
–
–
–
–
–
373
(44)
$ 3,704
$
–
–
2,619
476
338
107
61
1,046
–
–
–
8
$ 4,655
$
–
–
2,972
39
384
65
51
1,520
–
–
–
5
$ 5,036
$
–
–
–
–
–
–
–
–
–
843
–
54
$ 897
$
–
–
–
–
–
–
–
–
–
1,114
–
55
$ 1,169
$ 497
693
596
$ 497
693
28
635
319
2
5
345
102
155
211
17
$ 3,577
25
16
–
–
61
13
–
211
(2)
$ 1,542
$ 334
520
1,233
$ 334
520
402
578
230
2
4
671
115
177
222
39
$ 4,125
40
25
–
–
26
4
–
204
(3)
$ 1,552
$
–
–
568
610
276
–
5
284
89
–
–
17
$ 1,849
$
–
–
831
538
175
–
4
645
111
–
18
40
$ 2,362
$ –
–
–
–
27
2
–
–
–
155
–
2
$ 186
$ –
–
–
–
30
2
–
–
–
177
–
2
$ 211
1 U.S. equities include investments in the company’s common stock in the amount of $27 at December 31, 2012, and $35 at December 31, 2011.
2 Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly index funds. For these index funds, the Level 2 designation is
partially based on the restriction that advance notification of redemptions, typically two business days, is required.
3 Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.
4 The year-end valuations of the U.S. real estate assets are based on internal appraisals by the real estate managers, which are updates of third-party appraisals that occur at least once
a year for each property in the portfolio.
5 The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1); dividends and interest- and tax-related receivables (Level 2); insurance contracts
and investments in private-equity limited partnerships (Level 3).
60 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 61
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 20 Employee Benefit Plans – Continued
The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are
outlined below:
Total at December 31, 2010
Actual Return on Plan Assets:
Assets held at the reporting date
Assets sold during the period
Purchases, Sales and Settlements
Transfers in and/or out of Level 3
Total at December 31, 2011
Actual Return on Plan Assets:
Assets held at the reporting date
Assets sold during the period
Purchases, Sales and Settlements
Transfers in and/or out of Level 3
Total at December 31, 2012
The primary investment objectives of the pension plans
are to achieve the highest rate of total return within prudent
levels of risk and liquidity, to diversify and mitigate potential
downside risk associated with the investments, and to
provide adequate liquidity for benefit payments and
portfolio management.
The company’s U.S. and U.K. pension plans comprise
87 percent of the total pension assets. Both the U.S. and U.K.
plans have an Investment Committee that regularly meets
during the year to review the asset holdings and their returns.
To assess the plans’ investment performance, long-term asset
allocation policy benchmarks have been established.
For the primary U.S. pension plan, the company’s Bene-
fit Plan Investment Committee has established the following
approved asset allocation ranges: Equities 40–70 percent,
Fixed Income and Cash 20–65 percent, Real Estate 0–15
percent, and Other 0–5 percent. For the U.K. pension plan,
the U.K. Board of Trustees has established the following asset
allocation guidelines, which are reviewed regularly: Equities
50–70 percent and Fixed Income and Cash 30–50 percent.
The other significant international pension plans also have
established maximum and minimum asset allocation ranges
that vary by plan. Actual asset allocation within approved
ranges is based on a variety of current economic and market
conditions and consideration of specific asset class risk. To
mitigate concentration and other risks, assets are invested
across multiple asset classes with active investment managers
and passive index funds.
The company does not prefund its OPEB obligations.
Cash Contributions and Benefit Payments In 2012, the
company contributed $844 and $384 to its U.S. and
international pension plans, respectively. In 2013, the
company expects contributions to be approximately $650
62 Chevron Corporation 2012 Annual Report
Fixed Income
Mortgage-Backed
Securities
Real Estate
Other
$ 2
$ 738
$ 55
–
–
–
–
$ 2
–
–
–
–
$ 2
103
1
156
–
$ 998
108
2
182
–
$ 1,290
4
(2)
(1)
–
$ 56
1
–
–
–
$ 57
Total
$ 823
107
(1)
154
–
$ 1,083
109
2
186
–
$1,380
Corporate
$ 28
–
–
(1)
–
$ 27
–
–
4
–
$ 31
and $350 to its U.S. and international pension plans,
respectively. Actual contribution amounts are dependent
upon investment returns, changes in pension obligations,
regulatory environments and other economic factors. Additional
funding may ultimately be required if investment returns are
insufficient to offset increases in plan obligations.
The company anticipates paying other postretirement
benefits of approximately $228 in 2013, compared with $199
paid in 2012.
The following benefit payments, which include estimated
future service, are expected to be paid by the company in the
next 10 years:
2013
2014
2015
2016
2017
2018–2022
Pension Benefits
Int’l.
U.S.
$ 1,188
$ 1,192
$ 1,179
$ 1,180
$ 1,184
$ 5,650
$ 273
$ 338
$ 265
$ 291
$ 386
$ 2,353
Other
Benefits
$ 228
$ 234
$ 239
$ 245
$ 249
$ 1,292
Employee Savings Investment Plan Eligible employees
of Chevron and certain of its subsidiaries participate in the
Chevron Employee Savings Investment Plan (ESIP).
Charges to expense for the ESIP represent the company’s
contributions to the plan, which are funded either through
the purchase of shares of common stock on the open market
or through the release of common stock held in the leveraged
employee stock ownership plan (LESOP), which is described
in the section that follows. Total company matching con-
tributions to employee accounts within the ESIP were $286,
$263 and $253 in 2012, 2011 and 2010, respectively. This
cost was reduced by the value of shares released from the
LESOP totaling $43, $38 and $97 in 2012, 2011 and 2010,
Chevron Corporation 2012 Annual Report 63
Note 20 Employee Benefit Plans – Continued
respectively. The remaining amounts, totaling $243, $225
and $156 in 2012, 2011 and 2010, respectively, represent
open market purchases.
Employee Stock Ownership Plan Within the Chevron
ESIP is an employee stock ownership plan (ESOP). In 1989,
Chevron established a LESOP as a constituent part of the
ESOP. The LESOP provides partial prefunding of the com-
pany’s future commitments to the ESIP.
As permitted by accounting standards for share-based
compensation (ASC 718), the debt of the LESOP is recorded as
debt, and shares pledged as collateral are reported as “Deferred
compensation and benefit plan trust” on the Consolidated
Balance Sheet and the Consolidated Statement of Equity.
The company reports compensation expense equal to
LESOP debt principal repayments less dividends received
and used by the LESOP for debt service. Interest accrued
on LESOP debt is recorded as interest expense. Dividends
paid on LESOP shares are reflected as a reduction of retained
earnings. All LESOP shares are considered outstanding for
earnings-per-share computations.
Total expense (credits) for the LESOP were $1, $(1) and
$(1) in 2012, 2011 and 2010, respectively. The net credit for
the respective years was composed of credits to compensation
expense of $2, $5 and $6 and charges to interest expense for
LESOP debt of $3, $4 and $5.
Of the dividends paid on the LESOP shares, $18, $18
and $46 were used in 2012, 2011 and 2010, respectively, to
service LESOP debt. No contributions were required in 2011
or 2010, as dividends received by the LESOP were sufficient
to satisfy LESOP debt service. In 2012, the company con-
tributed $2 to the LESOP.
Shares held in the LESOP are released and allocated to
the accounts of plan participants based on debt service
deemed to be paid in the year in proportion to the total of
current-year and remaining debt service. LESOP shares as
of December 31, 2012 and 2011, were as follows:
Thousands
Allocated shares
Unallocated shares
Total LESOP shares
2012
2011
18,055
1,292
19,347
19,047
1,864
20,911
Benefit Plan Trusts Prior to its acquisition by Chevron,
Texaco established a benefit plan trust for funding obliga-
tions under some of its benefit plans. At year-end 2012,
the trust contained 14.2 million shares of Chevron treasury
stock. The trust will sell the shares or use the dividends from
the shares to pay benefits only to the extent that the company
does not pay such benefits. The company intends to continue
to pay its obligations under the benefit plans. The trustee will
vote the shares held in the trust as instructed by the trust’s
beneficiaries. The shares held in the trust are not considered
outstanding for earnings-per-share purposes until distributed
or sold by the trust in payment of benefit obligations.
Prior to its acquisition by Chevron, Unocal established
various grantor trusts to fund obligations under some of its
benefit plans, including the deferred compensation and sup-
plemental retirement plans. At December 31, 2012 and 2011,
trust assets of $48 and $51, respectively, were invested primarily
in interest-earning accounts.
Employee Incentive Plans The Chevron Incentive Plan is an
annual cash bonus plan for eligible employees that links
awards to corporate, unit and individual performance in the
prior year. Charges to expense for cash bonuses were $898,
$1,217 and $766 in 2012, 2011 and 2010, respectively.
Chevron also has the LTIP for officers and other regular sala-
ried employees of the company and its subsidiaries who hold
positions of significant responsibility. Awards under the LTIP
consist of stock options and other share-based compensation
that are described in Note 19, beginning on page 56.
Note 21
Equity
Retained earnings at December 31, 2012 and 2011, included
approximately $10,119 and $10,127, respectively, for the com-
pany’s share of undistributed earnings of equity affiliates.
At December 31, 2012, about 55 million shares of
Chevron’s common stock remained available for issuance from
the 160 million shares that were reserved for issuance under
the Chevron LTIP. In addition, approximately 231,000 shares
remain available for issuance from the 800,000 shares of the
company’s common stock that were reserved for awards under
the Chevron Corporation Non-Employee Directors’ Equity
Compensation and Deferral Plan.
Note 22
Other Contingencies and Commitments
Income Taxes The company calculates its income tax
expense and liabilities quarterly. These liabilities generally are
subject to audit and are not finalized with the individual tax-
ing authorities until several years after the end of the annual
period for which income taxes have been calculated. Refer to
Note 14, beginning on page 51, for a discussion of the periods
for which tax returns have been audited for the company’s
major tax jurisdictions and a discussion for all tax jurisdic-
tions of the differences between the amount of tax benefits
recognized in the financial statements and the amount taken
or expected to be taken in a tax return. As discussed on page
53, Chevron is currently assessing the potential impact of
a decision by the U.S. Court of Appeals for the Third Cir-
cuit that disallows the Historic Rehabilitation Tax Credits
Chevron Corporation 2012 Annual Report 63
62 Chevron Corporation 2012 Annual Report
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 22 Other Contingencies and Commitments – Continued
claimed by an unrelated taxpayer. It is reasonably possible
that the specific findings from this assessment could result
in a significant increase in unrecognized tax benefits, which
may have a material effect on the company’s results of opera-
tions in any one reporting period. The company does not
expect settlement of income tax liabilities associated with
uncertain tax positions to have a material effect on its con-
solidated financial position or liquidity.
Guarantees The company’s guarantee of $562 is associ-
ated with certain payments under a terminal use agreement
entered into by an equity affiliate. Over the approximate
15-year remaining term of the guarantee, the maximum
guarantee amount will be reduced over time as certain fees
are paid by the affiliate. There are numerous cross-indemnity
agreements with the affiliate and the other partners to permit
recovery of amounts paid under the guarantee. Chevron has
recorded no liability for its obligation under this guarantee.
Indemnifications The company provided certain indemni-
ties of contingent liabilities of Equilon and Motiva to Shell
and Saudi Refining, Inc., in connection with the February
2002 sale of the company’s interests in those investments.
Through the end of 2012, the company paid $48 under these
indemnities and continues to be obligated up to $250 for
possible additional indemnification payments in the future.
The company has also provided indemnities relating to
contingent environmental liabilities of assets originally con-
tributed by Texaco to the Equilon and Motiva joint ventures
and environmental conditions that existed prior to the for-
mation of Equilon and Motiva, or that occurred during the
period of Texaco’s ownership interest in the joint ventures. In
general, the environmental conditions or events that are sub-
ject to these indemnities must have arisen prior to December
2001. Claims had to be asserted by February 2009 for
Equilon indemnities and February 2012 for Motiva indem-
nities. In February 2012, Motiva Enterprises LLC delivered
a letter to the company purporting to preserve unmatured
claims for certain Motiva indemnities. The company had
previously provided a negative response to similar claims.
The letter itself provides no estimate of the ultimate claim
amount. Management does not believe this letter or any
other information provides a basis to estimate the amount, if
any, of a range of loss or potential range of loss with respect
to either the Equilon or the Motiva indemnities. The com-
pany posts no assets as collateral and has made no payments
under the indemnities.
Through December 31, 2012, the company has not
received further correspondence from Equilon and Motiva
Enterprises LLC, and the company does not expect further
action to occur related to the indemnities described in the
preceding paragraphs.
64 Chevron Corporation 2012 Annual Report
In the acquisition of Unocal, the company assumed
certain indemnities relating to contingent environmental
liabilities associated with assets that were sold in 1997. The
acquirer of those assets shared in certain environmental
remediation costs up to a maximum obligation of $200,
which had been reached at December 31, 2009. Under the
indemnification agreement, after reaching the $200 obliga-
tion, Chevron is solely responsible until April 2022, when
the indemnification expires. The environmental conditions or
events that are subject to these indemnities must have arisen
prior to the sale of the assets in 1997.
Although the company has provided for known obliga-
tions under this indemnity that are probable and reasonably
estimable, the amount of additional future costs may be
material to results of operations in the period in which they
are recognized. The company does not expect these costs will
have a material effect on its consolidated financial position or
liquidity.
Long-Term Unconditional Purchase Obligations and
Commitments, Including Throughput and Take-or-Pay
Agreements The company and its subsidiaries have certain
other contingent liabilities with respect to long-term uncon-
ditional purchase obligations and commitments, including
throughput and take-or-pay agreements, some of which relate
to suppliers’ financing arrangements. The agreements typi-
cally provide goods and services, such as pipeline and storage
capacity, drilling rigs, utilities, and petroleum products,
to be used or sold in the ordinary course of the company’s
business. The aggregate approximate amounts of required
payments under these various commitments are: 2013 –
$3,700; 2014 – $3,900; 2015 – $4,100; 2016 – $2,400; 2017
– $1,800; 2018 and after – $6,500. A portion of these com-
mitments may ultimately be shared with project partners.
Total payments under the agreements were approximately
$3,600 in 2012, $6,600 in 2011 and $6,500 in 2010.
Environmental The company is subject to loss contingen-
cies pursuant to laws, regulations, private claims and legal
proceedings related to environmental matters that are subject
to legal settlements or that in the future may require the
company to take action to correct or ameliorate the effects on
the environment of prior release of chemicals or petroleum
substances, including MTBE, by the company or other par-
ties. Such contingencies may exist for various sites, including,
but not limited to, federal Superfund sites and analogous sites
under state laws, refineries, crude oil fields, service stations,
terminals, land development areas, and mining operations,
whether operating, closed or divested. These future costs are
not fully determinable due to such factors as the unknown
magnitude of possible contamination, the unknown timing
and extent of the corrective actions that may be required,
Chevron Corporation 2012 Annual Report 65
Note 22 Other Contingencies and Commitments – Continued
the determination of the company’s liability in proportion to
other responsible parties, and the extent to which such costs
are recoverable from third parties.
Although the company has provided for known envi-
ronmental obligations that are probable and reasonably
estimable, the amount of additional future costs may be
material to results of operations in the period in which they
are recognized. The company does not expect these costs will
have a material effect on its consolidated financial position or
liquidity. Also, the company does not believe its obligations
to make such expenditures have had, or will have, any signifi-
cant impact on the company’s competitive position relative to
other U.S. or international petroleum or chemical companies.
Chevron’s environmental reserve as of December 31,
2012, was $1,403. Included in this balance were remediation
activities at approximately 175 sites for which the company
had been identified as a potentially responsible party or
otherwise involved in the remediation by the U.S. Environ-
mental Protection Agency (EPA) or other regulatory agencies
under the provisions of the federal Superfund law or analo-
gous state laws. The company’s remediation reserve for these
sites at year-end 2012 was $157. The federal Superfund law
and analogous state laws provide for joint and several liability
for all responsible parties. Any future actions by the EPA or
other regulatory agencies to require Chevron to assume other
potentially responsible parties’ costs at designated hazardous
waste sites are not expected to have a material effect on the
company’s results of operations, consolidated financial posi-
tion or liquidity.
Of the remaining year-end 2012 environmental reserves
balance of $1,246, $782 related to the company’s U.S. down-
stream operations, including refineries and other plants,
marketing locations (i.e., service stations and terminals),
chemical facilities, and pipelines. The remaining $464 was
associated with various sites in international downstream
$93, upstream $309 and other businesses $62. Liabilities at
all sites, whether operating, closed or divested, were primar-
ily associated with the company’s plans and activities to
remediate soil or groundwater contamination or both. These
and other activities include one or more of the following: site
assessment; soil excavation; offsite disposal of contaminants;
onsite containment, remediation and/or extraction of petro-
leum hydrocarbon liquid and vapor from soil; groundwater
extraction and treatment; and monitoring of the natural
attenuation of the contaminants.
The company manages environmental liabilities under
specific sets of regulatory requirements, which in the United
States include the Resource Conservation and Recovery Act
and various state and local regulations. No single remediation
site at year-end 2012 had a recorded liability that was mate-
rial to the company’s results of operations, consolidated
financial position or liquidity.
It is likely that the company will continue to incur addi-
tional liabilities, beyond those recorded, for environmental
remediation relating to past operations. These future costs are
not fully determinable due to such factors as the unknown
magnitude of possible contamination, the unknown timing
and extent of the corrective actions that may be required,
the determination of the company’s liability in proportion to
other responsible parties, and the extent to which such costs
are recoverable from third parties.
Refer to Note 23 on page 66 for a discussion of the com-
pany’s asset retirement obligations.
Other Contingencies On April 26, 2010, a California
appeals court issued a ruling related to the adequacy of an
Environmental Impact Report (EIR) supporting the issuance
of certain permits by the city of Richmond, California, to
replace and upgrade certain facilities at Chevron’s refinery
in Richmond. Settlement discussions with plaintiffs in the
case ended late fourth quarter 2010, and on March 3, 2011,
the trial court entered a final judgment and peremptory writ
ordering the City to set aside the project EIR and conditional
use permits and enjoining Chevron from any further work.
On May 23, 2011, the company filed an application with the
City Planning Department for a conditional use permit for
a revised project to complete construction of the hydrogen
plant, certain sulfur removal facilities and related infrastruc-
ture. On June 10, 2011, the City published its Notice of
Preparation of the revised EIR for the project. The revised
and recirculated EIR is intended to comply with the appeals
court decision. Management believes the outcomes associ-
ated with the project are uncertain. Due to the uncertainty of
the company’s future course of action, or potential outcomes
of any action or combination of actions, management does
not believe an estimate of the financial effects, if any, can be
made at this time.
Chevron receives claims from and submits claims to
customers; trading partners; U.S. federal, state and local
regulatory bodies; governments; contractors; insurers; and
suppliers. The amounts of these claims, individually and in
the aggregate, may be significant and take lengthy periods to
resolve.
The company and its affiliates also continue to review
and analyze their operations and may close, abandon, sell,
exchange, acquire or restructure assets to achieve operational
or strategic benefits and to improve competitiveness and prof-
itability. These activities, individually or together, may result
in gains or losses in future periods.
64 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 65
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 23
Asset Retirement Obligations
The company records the fair value of a liability for an asset
retirement obligation (ARO) as an asset and liability when
there is a legal obligation associated with the retirement of a
tangible long-lived asset and the liability can be reasonably
estimated. The legal obligation to perform the asset retire-
ment activity is unconditional, even though uncertainty may
exist about the timing and/or method of settlement that may
be beyond the company’s control. This uncertainty about the
timing and/or method of settlement is factored into the mea-
surement of the liability when sufficient information exists
to reasonably estimate fair value. Recognition of the ARO
includes: (1) the present value of a liability and offsetting
asset, (2) the subsequent accretion of that liability and depre-
ciation of the asset, and (3) the periodic review of the ARO
liability estimates and discount rates.
AROs are primarily recorded for the company’s crude
oil and natural gas producing assets. No significant AROs
associated with any legal obligations to retire downstream
long-lived assets have been recognized, as indeterminate set-
tlement dates for the asset retirements prevent estimation of
the fair value of the associated ARO. The company performs
periodic reviews of its downstream long-lived assets for any
changes in facts and circumstances that might require recog-
nition of a retirement obligation.
The following table indicates the changes to the company’s
before-tax asset retirement obligations in 2012, 2011 and 2010:
Balance at January 1
Liabilities incurred
Liabilities settled
Accretion expense
Revisions in estimated cash flows
Balance at December 31
2012
2011
2010
$ 12,767
133
(966)
629
708
$ 13,271
$ 12,488
62
(1,316)
628
905
$ 12,767
$ 10,175
129
(755)
513
2,426
$ 12,488
The long-term portion of the $13,271 balance at the end
of 2012 was $12,375.
Note 24
Other Financial Information
Earnings in 2012 included gains of approximately $2,800
relating to the sale of nonstrategic properties. Of this amount,
approximately $2,200 and $600 related to upstream and
downstream assets, respectively. Earnings in 2011 included
gains of approximately $1,300 relating to the sale of nonstra-
tegic properties. Of this amount, approximately $800 and
$500 related to downstream and upstream assets, respectively.
Other financial information is as follows:
Total financing interest and debt costs
Less: Capitalized interest
Interest and debt expense
Research and development expenses
Foreign currency effects*
Year ended December 31
2012
2011
2010
$ 242
242
$
–
$ 648
$ (454)
$ 288
288
–
$
$ 627
$ 121
$ 317
267
$ 50
$ 526
$ (423)
* Includes $(202), $(27) and $(71) in 2012, 2011 and 2010, respectively, for the com-
pany’s share of equity affiliates’ foreign currency effects.
The excess of replacement cost over the carrying value of
inventories for which the last-in, first-out (LIFO) method is
used was $9,292 and $9,025 at December 31, 2012 and 2011,
respectively. Replacement cost is generally based on average
acquisition costs for the year. LIFO profits (charges) of $121,
$193 and $21 were included in earnings for the years 2012,
2011 and 2010, respectively.
The company has $4,640 in goodwill on the Consoli-
dated Balance Sheet related to the 2005 acquisition of Unocal
and to the 2011 acquisition of Atlas Energy, Inc. Under the
accounting standard for goodwill (ASC 350), the company
tested this goodwill for impairment during 2012 and con-
cluded no impairment was necessary.
66 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 67
Note 25
Earnings Per Share
Basic earnings per share (EPS) is based upon “Net Income
Attributable to Chevron Corporation” (“earnings”) and
includes the effects of deferrals of salary and other compen-
sation awards that are invested in Chevron stock units by
certain officers and employees of the company. Diluted
EPS includes the effects of these items as well as the dilu-
tive effects of outstanding stock options awarded under
the company’s stock option programs (refer to Note 19,
“Stock Options and Other Share-Based Compensation,”
beginning on page 56). The table below sets forth
the computation of basic and diluted EPS:
Basic EPS Calculation
Earnings available to common stockholders – Basic*
Weighted-average number of common shares outstanding
Add: Deferred awards held as stock units
Total weighted-average number of common shares outstanding
Earnings per share of common stock – Basic
Diluted EPS Calculation
Earnings available to common stockholders – Diluted*
Weighted-average number of common shares outstanding
Add: Deferred awards held as stock units
Add: Dilutive effect of employee stock-based awards
Total weighted-average number of common shares outstanding
Earnings per share of common stock – Diluted
2012
2011
2010
Year ended December 31
$ 26,179
1,950
–
1,950
$ 13.42
$ 26,179
1,950
–
15
1,965
$ 13.32
$ 26,895
$ 19,024
1,986
–
1,986
1,996
1
1,997
$ 13.54
$
9.53
$ 26,895
$ 19,024
1,986
–
15
2,001
1,996
1
10
2,007
$ 13.44
$
9.48
*There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings.
66 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report 67
Properties were measured primarily using an income
approach. The fair values of the acquired oil and gas proper-
ties were based on significant inputs not observable in the
market and thus represent Level 3 measurements. Refer
to Note 8, beginning on page 41 for a definition of fair
value hierarchy levels. Significant inputs included estimated
resource volumes, assumed future production profiles, esti-
mated future commodity prices, a discount rate of 8 percent,
and assumptions on the timing and amount of future oper-
ating and development costs. All the properties are in the
United States and are included in the Upstream segment.
The acquisition date fair value of the consideration trans-
ferred was $3,400 in cash. The $27 of goodwill was assigned
to the Upstream segment and represents the amount of the
consideration transferred in excess of the values assigned to
the individual assets acquired and liabilities assumed. Good-
will represents the future economic benefits arising from
other assets acquired that could not be individually identified
and separately recognized. None of the goodwill is deduct-
ible for tax purposes. Goodwill recorded in the acquisition
is not subject to amortization, but will be tested periodically
for impairment as required by the applicable accounting stan-
dard (ASC 350).
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 26
Acquisition of Atlas Energy, Inc.
On February 17, 2011, the company acquired Atlas Energy,
Inc. (Atlas), which held one of the premier acreage positions in
the Marcellus Shale, concentrated in southwestern Pennsylva-
nia. The aggregate purchase price of Atlas was approximately
$4,500, which included $3,009 cash for all the common shares
of Atlas, a $403 cash advance to facilitate Atlas’ purchase of a
49 percent interest in Laurel Mountain Midstream LLC and
about $1,100 of assumed debt. Subsequent to the close of the
transaction, the company paid off the assumed debt and made
payments of $184 in connection with Atlas equity awards. As
part of the acquisition, Chevron assumed the terms of a carry
arrangement whereby Reliance Marcellus, LLC, funds 75 per-
cent of Chevron’s drilling costs, up to $1,300.
The acquisition was accounted for as a business combina-
tion (ASC 805) which, among other things, requires assets
acquired and liabilities assumed to be measured at their
acquisition date fair values. Provisional fair value measure-
ments were made in first quarter 2011 for acquired assets and
assumed liabilities, and the measurement process was final-
ized in fourth quarter 2011.
Proforma financial information is not presented, as it
would not be materially different from the information pre-
sented in the Consolidated Statement of Income.
The following table summarizes the measurement of the
assets acquired and liabilities assumed:
At February 17, 2011
Current assets
Investments and long-term receivables
Properties
Goodwill
Other assets
Total assets acquired
Current liabilities
Long-term debt and capital leases
Deferred income taxes
Other liabilities
Total liabilities assumed
Net assets acquired
$ 155
456
6,051
27
5
6,694
(560)
(761)
(1,915)
(25)
(3,261)
$ 3,433
68 Chevron Corporation 2012 Annual Report
Five-Year Financial Summary
Unaudited
Millions of dollars, except per-share amounts
2012
2011
2010
2009
2008
Statement of Income Data
Revenues and Other Income
Total sales and other operating revenues*
Income from equity affiliates and other income
Total Revenues and Other Income
Total Costs and Other Deductions
Income Before Income Tax Expense
Income Tax Expense
Net Income
Less: Net income attributable to noncontrolling interests
Net Income Attributable to Chevron Corporation
Per Share of Common Stock
Net Income Attributable to Chevron
– Basic
– Diluted
Cash Dividends Per Share
Balance Sheet Data (at December 31)
Current assets
Noncurrent assets
Total Assets
Short-term debt
Other current liabilities
Long-term debt and capital lease obligations
Other noncurrent liabilities
Total Liabilities
Total Chevron Corporation Stockholders’ Equity
Noncontrolling interests
Total Equity
$ 230,590
11,319
241,909
195,577
46,332
19,996
26,336
157
$ 26,179
$ 244,371
9,335
253,706
206,072
47,634
20,626
27,008
113
$ 26,895
$ 198,198
6,730
204,928
172,873
32,055
12,919
19,136
112
$ 19,024
$ 167,402
4,234
171,636
153,108
18,528
7,965
10,563
80
$ 10,483
$ 264,958
8,047
273,005
229,948
43,057
19,026
24,031
100
$ 23,931
$
$
$
13.42
13.32
3.51
$
$
$
13.54
13.44
3.09
$
$
$
9.53
9.48
2.84
$
$
$
5.26
5.24
2.66
$
$
$
11.74
11.67
2.53
$ 55,720
177,262
232,982
127
34,085
12,065
48,873
95,150
$ 136,524
1,308
$ 137,832
$ 53,234
156,240
209,474
340
33,260
9,812
43,881
87,293
$ 121,382
799
$ 48,841
135,928
184,769
187
28,825
11,289
38,657
78,958
$ 105,081
730
$ 37,216
127,405
164,621
384
25,827
10,130
35,719
72,060
$ 91,914
647
$ 36,470
124,695
161,165
2,818
29,205
6,083
35,942
74,048
$ 86,648
469
$ 122,181
$ 105,811
$ 92,561
$ 87,117
*Includes excise, value-added and similar taxes:
$ 8,010
$ 8,085
$ 8,591
$ 8,109
$ 9,846
Chevron Corporation 2012 Annual Report 69
Five-Year Operating Summary
Unaudited
Worldwide – Includes Equity in Affiliates
Thousands of barrels per day, except natural gas data,
which is millions of cubic feet per day
United States
Net production of crude oil and natural gas liquids
Net production of natural gas1
Net oil-equivalent production
Refinery input
Sales of refined products
Sales of natural gas liquids
Total sales of petroleum products
Sales of natural gas
International
Net production of crude oil and natural gas liquids2
Other produced volumes3
Net production of natural gas1
Net oil-equivalent production
Refinery input
Sales of refined products
Sales of natural gas liquids
Total sales of petroleum products
Sales of natural gas
Total Worldwide
Net production of crude oil and natural gas liquids
Other produced volumes
Net production of natural gas1
Net oil-equivalent production
Refinery input
Sales of refined products
Sales of natural gas liquids
Total sales of petroleum products
Sales of natural gas
Worldwide – Excludes Equity in Affiliates
Number of wells completed (net)4
Oil and gas
Dry
Productive oil and gas wells (net)4
1 Includes natural gas consumed in operations:
United States
International
Total
2 Includes: Canada-synthetic oil
Venezuela affiliate-synthetic oil
3 Includes: Canada oil sands
4 Net wells include wholly owned and the sum of fractional interests in partially owned wells.
2012
2011
2010
2009
2008
455
1,203
655
833
1,211
157
1,368
5,470
1,309
–
3,871
1,955
869
1,554
88
1,642
4,315
1,764
–
5,074
2,610
1,702
2,765
245
3,010
9,785
1,618
28
55,812
63
523
586
43
17
–
465
1,279
678
854
1,257
161
1,418
5,836
1,384
–
3,662
1,995
933
1,692
87
1,779
4,361
1,849
–
4,941
2,673
1,787
2,949
248
3,197
10,197
1,551
27
55,049
69
513
582
40
32
–
489
1,314
708
890
1,349
161
1,510
5,932
1,434
–
3,726
2,055
1,004
1,764
105
1,869
4,493
1,923
–
5,040
2,763
1,894
3,113
266
3,379
10,425
1,160
31
51,677
62
475
537
24
28
–
484
1,399
717
899
1,403
161
1,564
5,901
1,362
26
3,590
1,987
979
1,851
111
1,962
4,062
1,846
26
4,989
2,704
1,878
3,254
272
3,526
9,963
1,265
24
51,326
58
463
521
–
–
26
421
1,501
671
891
1,413
159
1,572
7,226
1,228
27
3,624
1,859
967
2,016
114
2,130
4,215
1,649
27
5,125
2,530
1,858
3,429
273
3,702
11,441
1,648
12
51,262
70
450
520
–
–
27
70 Chevron Corporation 2012 Annual Report
70 Chevron Corporation 2012 Annual Report
Chevron Corporation 2012 Annual Report PB
Supplemental Information on Oil and Gas Producing Activities
Unaudited
In accordance with FASB and SEC disclosure and reporting
requirements for oil and gas producing activities, this section
provides supplemental information on oil and gas exploration
and producing activities of the company in seven separate
tables. Tables I through IV provide historical cost informa-
tion pertaining to costs incurred in exploration, property
acquisitions and development; capitalized costs; and results
of operations. Tables V through VII present information
Table I – Costs Incurred in Exploration, Property Acquisitions and Development1
Millions of dollars
Year Ended December 31, 2012
Exploration
Wells
Geological and geophysical
Rentals and other
Total exploration
Property acquisitions2
Proved
Unproved
Total property acquisitions
Development3
Total Costs Incurred4
Year Ended December 31, 2011
Exploration
Wells
Geological and geophysical
Rentals and other
Total exploration
Property acquisitions2
Proved
Unproved
Total property acquisitions
Development3
Total Costs Incurred4
Year Ended December 31, 2010
Exploration
Wells
Geological and geophysical
Rentals and other
Total exploration
Property acquisitions2
Proved
Unproved
Total property acquisitions
Development3
Total Costs Incurred
U.S.
Other
Americas
Africa
Asia
Australia
Europe
Total
TCO
Other
Consolidated Companies
Affiliated Companies
$
251
99
161
511
248
1,150
1,398
6,597
$ 8,506
$
321
76
109
506
1,174
7,404
8,578
5,517
$ 14,601
$
99
67
121
287
24
359
383
$ 202
105
55
$ 121
107
93
$ 271
86
201
362
321
558
$ 302
47
85
434
$ 88
58
107
253
–
29
29
8
5
13
39
342
381
–
28
28
–
–
–
$ 1,235
502
702
2,439
295
1,554
1,849
$
–
–
–
–
–
–
–
$
–
–
–
–
–
28
28
1,211
3,118
3,797
$ 1,602
$ 3,452
$ 4,736
4,555
$ 5,017
753
$ 1,006
20,031
$ 24,319
660
$ 660
293
$ 321
$
71
59
45
175
16
228
244
$
$ 104
65
83
252
–
–
–
146
121
67
334
1
–
1
$
242
23
71
336
–
–
–
$ 188
43
78
309
–
25
25
$ 1,072
387
453
1,912
1,191
7,657
8,848
$
–
–
–
–
–
–
–
$
–
–
–
–
–
–
–
1,537
2,698
2,867
$ 1,956
$ 2,950
$ 3,202
2,638
$ 2,974
633
$ 967
15,890
$ 26,650
379
$ 379
368
$ 368
$
$ 118
46
39
203
–
429
429
94
87
55
236
–
160
160
$
244
29
47
320
129
187
316
$
293
8
95
396
–
–
–
$ 61
18
57
136
–
10
10
$
909
255
414
1,578
153
1,145
1,298
$
–
–
–
–
–
–
–
$
–
–
–
–
–
–
–
4,446
$ 5,116
1,611
2,985
3,325
$ 2,243
$ 3,381
$ 3,961
2,623
$ 3,019
411
$ 557
15,401
$ 18,277
230
$ 230
343
$ 343
1 Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 23,
“Asset Retirement Obligations,” on page 66.
2 Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired in nonmonetary transactions, such as $1,850 million related to the 2012 acquisi-
tion of Clio and Acme fields in Australia.
3 Includes $963, $1,035 and $745 costs incurred prior to assignment of proved reserves for consolidated companies in 2012, 2011 and 2010, respectively.
4 Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures – $ billions.
Total cost incurred for 2012
Non oil and gas activities
ARO
(Includes LNG and gas-to-liquids $4.6, transportation $0.6, affiliate $0.4, other $0.2)
$ 25.3
5.8
(0.7)
$ 30.4 Reference page 20 upstream total
Upstream C&E
Chevron Corporation 2012 Annual Report 71
Table I Costs Incurred in Exploration,
Property Acquisitions and Development – Continued
on the company’s estimated net proved-reserve quantities,
stan dardized measure of estimated discounted future net cash
flows related to proved reserves and changes in estimated
discounted future net cash flows. The Africa geographic area
includes activities principally in Angola, Chad, Democratic
Republic of the Congo, Nigeria and Republic of the Congo.
The Asia geographic area includes activities principally in
Azerbaijan, Bangladesh, China, Indonesia, Kazakhstan,
Myanmar, the Partitioned Zone between Kuwait and Saudi
Arabia, the Philippines, and Thailand. The Europe geo-
graphic area includes activity in Denmark, the Netherlands,
Norway and the United Kingdom. The Other Americas
geographic region includes activities in Argentina, Brazil,
Canada, Colombia, and Trinidad and Tobago. Amounts
for TCO represent Chevron’s 50 percent equity share of
Tengizchevroil, an exploration and production partnership in
the Republic of Kazakhstan. The affiliated companies Other
amounts are composed of the company’s equity interests in
Venezuela and Angola. Refer to Note 11, beginning on page
46, for a dis cussion of the company’s major equity affiliates.
Table II – Capitalized Costs Related to Oil and Gas Producing Activities
Millions of dollars
At December 31, 2012
Unproved properties
Proved properties and
related producing assets
Support equipment
Deferred exploratory wells
Other uncompleted projects
Gross Capitalized Costs
Unproved properties valuation
Proved producing properties –
Depreciation and depletion
Support equipment depreciation
Accumulated provisions
Net Capitalized Costs
At December 31, 2011
Unproved properties
Proved properties and
related producing assets
Support equipment
Deferred exploratory wells
Other uncompleted projects
Gross Capitalized Costs
Unproved properties valuation
Proved producing properties –
Depreciation and depletion
Support equipment depreciation
Accumulated provisions
Net Capitalized Costs
U.S.
Other
Americas
Africa
Asia
Australia
Europe
Total
TCO
Other
Consolidated Companies
Affiliated Companies
$ 10,478
$ 1,415
$
271
$ 2,039 $ 1,884
$
34 $ 16,121
$ 109
$
28
62,274
1,179
412
7,203
81,546
1,121
42,224
589
43,934
$ 37,612
11,237
330
201
3,211
30,106
1,195
598
3,466
39,889
1,554
326
4,123
2,420
1,191
911
9,754
9,994
172
233
768
155,920
5,621
2,681
28,525
16,394
35,636
47,931
16,160
11,201
208,868
634
201
253
2
28
2,239
5,288
178
15,566
613
24,432
1,101
6,100
16,380
25,786
1,832
305
2,139
8,255
137
97,597
2,923
8,420
102,759
$ 10,294
$ 19,256
$ 22,145 $ 14,021
$ 2,781 $ 106,109
6,832
1,089
–
906
8,936
41
2,274
480
2,795
$ 6,141
1,852
–
–
1,594
3,474
–
551
–
551
$ 2,923
$ 9,806
$ 1,417
$
368
$ 2,408 $
6
$
33
$
14,038
$ 109
$
–
57,674
1,071
565
4,887
11,029
292
63
2,408
25,549
1,362
629
4,773
36,740
1,544
260
3,109
74,003
15,209
32,681
44,061
1,085
498
178
262
39,210
530
40,825
4,826
175
5,499
13,173
715
20,991
1,192
14,066
22,445
2,244
533
709
6,076
9,568
2
1,574
238
1,814
9,549
169
208
492
10,451
13
7,742
129
7,884
142,785
4,971
2,434
21,745
185,973
2,038
87,516
2,979
92,533
$ 33,178
$ 9,710
$ 18,615
$ 21,616 $ 7,754
$ 2,567
$
93,440
6,583
1,018
–
605
8,315
38
1,910
451
2,399
$ 5,916
1,607
–
–
1,466
3,073
–
436
–
436
$ 2,637
72 Chevron Corporation 2012 Annual Report
Table II Capitalized Costs Related to Oil and
Gas Producing Activities – Continued
Millions of dollars
At December 31, 2010
Unproved properties
Proved properties and
related producing assets
Support equipment
Deferred exploratory wells
Other uncompleted projects
Gross Capitalized Costs
Unproved properties valuation
Proved producing properties –
Depreciation and depletion
Support equipment depreciation
Accumulated provisions
Net Capitalized Costs
U.S.
Other
Americas
Africa
Asia
Australia
Europe
Total
TCO
Other
Consolidated Companies
Affiliated Companies
$ 2,553
$ 1,349
$
359
$ 2,561 $
6
$
8
$
6,836
$ 108
$
–
55,601
975
743
2,299
7,747
265
210
3,844
23,683
1,282
611
4,061
33,316
1,421
224
3,627
62,171
13,415
29,996
41,149
967
436
150
200
37,682
518
39,167
3,986
153
4,575
10,986
600
18,197
1,126
11,736
19,523
2,585
259
732
3,631
7,213
2
1,718
84
1,804
9,035
165
198
362
9,768
–
7,162
114
7,276
131,967
4,367
2,718
17,824
163,712
1,755
79,731
2,595
84,081
$ 23,004
$ 8,840
$ 18,260
$ 21,626 $ 5,409
$ 2,492
$
79,631
6,512
985
–
357
7,962
34
1,530
402
1,966
$ 5,996
1,594
–
–
1,001
2,595
–
249
–
249
$ 2,346
Chevron Corporation 2012 Annual Report 73
Table III Results of Operations for Oil and
Gas Producing Activities1
The company’s results of operations from oil and gas
producing activities for the years 2012, 2011 and 2010 are
shown in the following table. Net income from exploration
and production activities as reported on page 45 reflects
income taxes computed on an effective rate basis.
Income taxes in Table III are based on statutory tax rates,
reflecting allowable deductions and tax credits. Interest
income and expense are excluded from the results reported in
Table III and from the net income amounts on page 45.
Table III – Results of Operations for Oil and Gas Producing Activities1
Millions of dollars
Year Ended December 31, 2012
Revenues from net production
Sales
Transfers
Total
Production expenses excluding taxes
Taxes other than on income
Proved producing properties:
Depreciation and depletion
Accretion expense2
Exploration expenses
Unproved properties valuation
Other income (expense)3
Results before income taxes
Income tax expense
Results of Producing Operations
Year Ended December 31, 20114
Revenues from net production
Sales
Transfers
Total
Production expenses excluding taxes
Taxes other than on income
Proved producing properties:
Depreciation and depletion
Accretion expense2
Exploration expenses
Unproved properties valuation
Other income (expense)3
Results before income taxes
Income tax expense
Results of Producing Operations
U.S.
Other
Americas
Africa
Asia
Australia
Europe
Total
TCO
Other
Consolidated Companies
Affiliated Companies
$ 1,832
15,122
16,954
(4,009)
(654)
(3,462)
(226)
(244)
(127)
167
8,399
(3,043)
$ 5,356
$ 2,508
15,811
18,319
(3,668)
(597)
(3,366)
(291)
(207)
(134)
163
10,219
(3,728)
$ 6,491
$ 1,561
1,997
3,558
(1,073)
(123)
$ 1,480
15,033
16,513
(1,918)
(161)
(508)
(33)
(145)
(138)
(169)
1,369
(310)
$ 1,059
(2,475)
(66)
(427)
(16)
(199)
11,251
(7,558)
$ 3,693
$ 2,047
2,624
4,671
(1,061)
(137)
$ 1,174
15,726
16,900
(1,526)
(153)
(796)
(27)
(144)
(146)
(466)
1,894
(535)
$ 1,359
(2,225)
(106)
(188)
(27)
(409)
12,266
(7,802)
$ 4,464
$ 10,485
9,071
19,556
(4,545)
(191)
(3,399)
(92)
(489)
(133)
245
10,952
(5,739)
$ 5,213
$ 9,431
8,962
18,393
(4,489)
(242)
(2,923)
(81)
(271)
(60)
231
10,558
(5,374)
$ 5,184
$ 1,539
1,073
2,612
(164)
(390)
(315)
(23)
(133)
–
2,495
4,082
(1,226)
$ 2,856
$ 1,474
1,012
2,486
(117)
(396)
(136)
(18)
(128)
–
(18)
1,673
(507)
$ 1,166
$ 1,618
2,148
3,766
(637)
(3)
(541)
(46)
(272)
(15)
13
2,265
(1,511)
754
$
$ 1,868
2,672
4,540
(564)
(2)
(580)
(39)
(277)
(14)
(74)
2,990
(1,913)
$ 1,077
$ 18,515
44,444
62,959
(12,346)
(1,522)
(10,700)
(486)
(1,710)
(429)
2,552
38,318
(19,387)
$ 18,931
$ 18,502
46,807
65,309
(11,425)
(1,527)
(10,026)
(562)
(1,215)
(381)
(573)
39,600
(19,859)
$ 19,741
$ 7,869
–
7,869
(463)
(439)
(427)
(8)
–
–
27
6,559
(1,972)
$ 4,587
$ 8,581
–
8,581
(449)
(429)
(442)
(8)
–
–
(8)
7,245
(2,176)
$ 5,069
$ 1,951
–
1,951
(442)
(767)
(147)
(6)
–
–
31
620
(299)
$ 321
$ 1,988
–
1,988
(235)
(815)
(140)
(4)
–
–
(29)
765
(392)
$ 373
1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in
calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page 66.
3 Includes foreign currency gains and losses, gains and losses on property dispositions (primarily related to Browse and Wheatstone gains in 2012), and other miscellaneous income and expenses.
4 2011 and 2010 conformed to 2012 presentation.
74 Chevron Corporation 2012 Annual Report
Table III Results of Operations for Oil and
Gas Producing Activities1 – Continued
Millions of dollars
Year Ended December 31, 20104
Revenues from net production
Sales
Transfers
Total
Production expenses excluding taxes
Taxes other than on income
Proved producing properties:
Depreciation and depletion
Accretion expense2
Exploration expenses
Unproved properties valuation
Other income (expense)3
Results before income taxes
Income tax expense
Results of Producing Operations
Other
Americas
U.S.
Africa
Asia
Australia
Europe
Total
TCO
Other
Consolidated Companies
Affiliated Companies
$ 2,540
12,172
14,712
(3,338)
(542)
(3,639)
(240)
(193)
(123)
(154)
6,483
(2,273)
$ 4,210
$ 1,881
1,147
3,028
(805)
(102)
$ 2,278
10,306
12,584
(1,413)
(130)
(907)
(23)
(173)
(71)
(367)
580
(223)
357
(2,204)
(102)
(242)
(25)
(103)
8,365
(4,535)
$ 3,830
$
$ 7,221
6,242
13,463
(2,996)
(85)
(2,816)
(35)
(289)
(33)
(282)
6,927
(3,886)
$ 3,041
$
994
985
1,979
(96)
(334)
(151)
(15)
(175)
–
109
1,317
(325)
992
$
$ 1,519
2,138
3,657
(534)
(2)
(681)
(53)
(75)
(2)
165
2,475
(1,455)
$ 1,020
$ 16,433
32,990
49,423
(9,182)
(1,195)
(10,398)
(468)
(1,147)
(254)
(632)
26,147
(12,697)
$ 13,450
$ 6,031
–
6,031
(347)
(360)
(432)
(8)
(5)
–
(65)
4,814
(1,445)
$ 3,369
$ 1,307
–
1,307
(152)
(101)
(131)
(5)
–
–
191
1,109
(615)
$ 494
1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in
calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page 66.
3 Includes foreign currency gains and losses, gains and losses on property dispositions, and other miscellaneous income and expenses.
4 2011 and 2010 conformed to 2012 presentation.
Chevron Corporation 2012 Annual Report 75
Table IV Results of Operations for Oil and
Gas Producing Activities — Unit Prices and Costs1
Year Ended December 31, 2012
Average sales prices
Liquids, per barrel
Natural gas, per thousand cubic feet
Average production costs, per barrel2
Year Ended December 31, 20113
Average sales prices
Liquids, per barrel
Natural gas, per thousand cubic feet
Average production costs, per barrel2
Year Ended December 31, 20103
Average sales prices
Liquids, per barrel
Natural gas, per thousand cubic feet
Average production costs, per barrel2
U.S.
Other
Americas
Africa
Asia
Australia
Europe
Total
TCO
Other
Consolidated Companies
Affiliated Companies
$ 95.21
2.65
16.99
$ 87.87
3.59
18.38
$ 109.64
1.22
12.14
$ 102.46 $ 103.06
10.99
4.86
6.03
16.71
$ 108.77
10.10
15.72
$ 101.61
5.42
15.46
$ 89.34
1.36
4.42
$ 83.97
5.39
18.73
$ 97.51
4.02
15.08
$ 89.87
2.97
14.62
$ 109.45
0.41
9.48
$ 100.55
5.28
17.47
$ 103.70
9.98
3.41
$ 107.11
9.91
11.44
$ 101.63
5.29
13.98
$ 94.60
1.60
4.23
$ 90.90
6.57
10.54
$ 71.59
4.25
13.11
$ 66.22
2.52
11.86
$ 78.00
0.73
8.57
$ 70.96
4.45
11.71
$ 76.43
6.76
2.55
$ 76.10
7.09
9.42
$ 73.24
4.55
10.96
$ 63.94
1.41
3.14
$ 64.92
4.20
7.37
1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net
production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2 Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.
3 2011 and 2010 conformed to 2012 presentation.
Table V Reserve Quantity Information
Reserves Governance The company has adopted a compre-
hensive reserves and resource classification system modeled
after a system developed and approved by the Society of
Petroleum Engineers, the World Petroleum Congress and
the American Association of Petroleum Geologists. The sys-
tem classifies recoverable hydrocarbons into six categories
based on their status at the time of reporting – three deemed
commercial and three potentially recoverable. Within the
commercial classification are proved reserves and two cat-
egories of unproved: probable and possible. The potentially
recoverable categories are also referred to as contingent
resources. For reserves estimates to be classified as proved,
they must meet all SEC and company standards.
Proved oil and gas reserves are the estimated quantities
that geoscience and engineering data demonstrate with rea-
sonable certainty to be economically producible in the future
from known reservoirs under existing economic conditions,
operating methods and government regulations. Net proved
reserves exclude royalties and interests owned by others and
reflect contractual arrangements and royalty obligations in
effect at the time of the estimate.
Proved reserves are classified as either developed or unde-
veloped. Proved developed reserves are the quantities expected
to be recovered through existing wells with existing equip-
ment and operating methods.
Due to the inherent uncertainties and the limited nature
of reservoir data, estimates of reserves are subject to change as
additional information becomes available.
76 Chevron Corporation 2012 Annual Report
Proved reserves are estimated by company asset teams
composed of earth scientists and engineers. As part of the
internal control process related to reserves estimation, the
company maintains a Reserves Advisory Committee (RAC)
that is chaired by the Manager of Corporate Reserves, a cor-
porate department that reports directly to the Vice Chairman
responsible for the company’s worldwide exploration and
production activities. The Manager of Corporate Reserves has
more than 30 years’ experience working in the oil and gas
industry and a Master of Science in Petroleum Engineering
degree from Stanford University. His experience includes
more than 15 years of managing oil and gas reserves processes.
He was chairman of the Society of Petroleum Engineers Oil
and Gas Reserves Committee, served on the United Nations
Expert Group on Resources Classification, and is a past mem-
ber of the Joint Committee on Reserves Evaluator Training
and the California Conservation Committee. He is an active
member of the Society of Petroleum Evaluation Engineers
and serves on the Society of Petroleum Engineers Oil and Gas
Reserves Committee.
All RAC members are degreed professionals, each
with more than 15 years of experience in various aspects of
reserves estimation relating to reservoir engineering, petro-
leum engineering, earth science or finance. The members
are knowledgeable in SEC guidelines for proved reserves
classification and receive annual training on the preparation
of reserves estimates. The reserves activities are managed by
two operating company-level reserves managers. These two
reserves managers are not members of the RAC so as to pre-
serve corporate-level independence.
Table V Reserve Quantity Information – Continued
Summary of Net Oil and Gas Reserves
Liquids in Millions of Barrels
Natural Gas in Billions of Cubic Feet
Proved Developed
Consolidated Companies
U.S.
Other Americas
Africa
Asia
Australia
Europe
Total Consolidated
Affiliated Companies
TCO
Other
Total Consolidated and Affiliated Companies
Proved Undeveloped
Consolidated Companies
U.S.
Other Americas
Africa
Asia
Australia
Europe
Total Consolidated
Affiliated Companies
TCO
Other
Total Consolidated and Affiliated Companies
Total Proved Reserves
* Based on 12-month average price.
2012*
2011*
2010*
Crude Oil
Condensate
NGLs
Synthetic
Oil
Natural
Gas
Crude Oil
Condensate
NGLs
Synthetic
Oil
Natural
Gas
Crude Oil
Condensate
NGLs
Synthetic
Oil
Natural
Gas
1,012
91
782
643
31
103
2,662
977
115
3,754
347
132
348
194
103
54
1,178
755
49
1,982
5,736
–
391
–
–
–
–
391
–
50
441
–
122
–
–
–
–
122
–
182
304
745
2,574
1,063
1,163
4,511
682
191
10,184
1,261
377
11,822
1,148
412
1,918
2,356
9,570
66
15,470
1,038
865
17,373
29,195
990
82
792
703
39
116
2,722
1,019
93
3,834
321
31
363
191
101
43
1,050
740
64
1,854
5,688
–
403
–
–
–
–
403
–
50
453
–
120
–
–
–
–
120
–
194
314
767
2,486
1,147
1,276
4,300
813
204
10,226
1,400
75
11,701
1,160
517
1,920
2,421
8,931
54
15,003
851
1,128
16,982
28,683
1,045
84
830
826
39
136
2,960
1,128
95
4,183
230
24
338
187
49
16
844
692
62
1,598
5,781
–
352
–
–
–
–
352
–
53
405
–
114
–
–
–
–
114
–
203
317
722
2,113
1,490
1,304
4,836
881
235
10,859
1,484
70
12,413
359
325
1,640
2,357
5,175
40
9,896
902
1,040
11,838
24,251
The RAC has the following primary responsibilities:
establish the policies and processes used within the operat-
ing units to estimate reserves; provide independent reviews
and oversight of the business units’ recommended reserves
estimates and changes; confirm that proved reserves are rec-
ognized in accordance with SEC guidelines; determine that
reserve volumes are calculated using consistent and appro-
priate standards, procedures and technology; and maintain
the Corporate Reserves Manual, which provides standardized
procedures used corporatewide for classifying and reporting
hydrocarbon reserves.
During the year, the RAC is represented in meetings with
each of the company’s upstream business units to review and
discuss reserve changes recommended by the various asset
teams. Major changes are also reviewed with the company’s
Strategy and Planning Committee, whose members include
the Chief Executive Officer and the Chief Financial Officer.
The company’s annual reserve activity is also reviewed with the
Board of Directors. If major changes to reserves were to occur
between the annual reviews, those matters would also be dis-
cussed with the Board.
RAC subteams also conduct in-depth reviews during
the year of many of the fields that have large proved reserves
quantities. These reviews include an examination of the
proved-reserve records and documentation of their compli-
ance with the Corporate Reserves Manual.
Technologies Used in Establishing Proved Reserves
Additions In 2012, additions to Chevron’s proved reserves
were based on a wide range of geologic and engineering tech-
nologies. Information generated from wells, such as well logs,
wire line sampling, production and pressure testing, fluid
analysis, and core analysis, was integrated with seismic data,
regional geologic studies, and information from analogous
reservoirs to provide “reasonably certain” proved reserves esti-
mates. Both proprietary and commercially available analytic
tools, including reservoir simulation, geologic modeling and
seismic processing, have been used in the interpretation of
the subsurface data. These technologies have been utilized
extensively by the company in the past, and the company
believes that they provide a high degree of confidence in
establishing reliable and consistent reserves estimates.
Chevron Corporation 2012 Annual Report 77
2,662
391
10,184
2,722
403
10,226
2,960
352
10,859
Total Consolidated and Affiliated Companies
3,754
441
11,822
–
50
1,261
377
1,019
93
3,834
–
50
453
1,400
75
11,701
–
53
1,484
70
405
12,413
Summary of Net Oil and Gas Reserves
Liquids in Millions of Barrels
Natural Gas in Billions of Cubic Feet
Proved Developed
Consolidated Companies
U.S.
Other Americas
Africa
Asia
Australia
Europe
TCO
Other
Total Consolidated
Affiliated Companies
Proved Undeveloped
Consolidated Companies
U.S.
Other Americas
Africa
Asia
Australia
Europe
TCO
Other
Total Consolidated
Affiliated Companies
2012*
2011*
2010*
Crude Oil
Crude Oil
Crude Oil
Condensate
Synthetic
Natural
Condensate
Synthetic
Natural
Condensate
Synthetic
Natural
NGLs
Oil
Gas
NGLs
Oil
Gas
NGLs
Oil
Gas
1,012
391
403
352
–
–
–
–
–
–
–
–
–
–
2,486
1,147
1,276
4,300
813
204
1,160
517
1,920
2,421
8,931
54
91
782
643
31
103
977
115
347
132
348
194
103
54
2,574
1,063
1,163
4,511
682
191
1,148
412
1,918
2,356
9,570
66
–
–
–
–
–
–
–
–
–
–
–
990
82
792
703
39
116
321
31
363
191
101
43
740
64
1,854
5,688
1,045
84
830
826
39
136
1,128
95
4,183
230
24
338
187
49
16
844
692
62
1,598
5,781
2,113
1,490
1,304
4,836
881
235
359
325
1,640
2,357
5,175
40
–
–
–
–
–
–
–
–
–
–
–
114
9,896
902
1,040
11,838
24,251
203
317
722
122
120
114
Total Consolidated and Affiliated Companies
Total Proved Reserves
* Based on 12-month average price.
1,178
122
15,470
1,050
120
15,003
755
49
1,982
5,736
1,038
865
17,373
29,195
182
304
745
–
194
314
767
851
1,128
16,982
28,683
Table V Reserve Quantity Information – Continued
Proved Undeveloped Reserve Quantities At the end
of 2012, proved undeveloped reserves totaled 5.2 billion bar-
rels of oil-equivalent (BOE). Approximately 56 percent of
these reserves are attributed to natural gas, of which about 55
percent were located in Australia. Crude oil, condensate and
natural gas liquids (NGLs) accounted for about 38 percent
of the total proved undeveloped reserves, of which about 38
percent were from TCO, and the remaining large concentra-
tions were in Africa, Asia and the United States. Synthetic
oil accounted for the balance of the proved undeveloped
reserves.
In 2012, a total of 394 million BOE was transferred
from proved undeveloped to proved developed. In Asia, 98
million BOE were transferred to proved developed primarily
driven by development drilling performance. In the United
States, approximately 95 million BOE were transferred,
primarily due to ongoing drilling activities in the deepwater
Gulf of Mexico and California. Affiliates accounted for 104
million BOE transferred to proved developed due to ongoing
development activities. Development drilling and the start
up of several projects in Africa, Europe and Other Americas
accounted for the remainder.
Investment to Convert Proved Undeveloped to Proved
Developed Reserves During 2012, investments totaling
approximately $10.7 billion in oil and gas producing activi-
ties and about $3.5 billion in non-oil and gas producing
activities were expended to advance the development of
proved undeveloped reserves. Australia accounted for $7.7
billion of the total, mainly for development and construction
activities at the Gorgon and Wheatstone LNG projects. In
Africa, another $2.3 billion was expended on various offshore
development and natural gas projects in Nigeria and Angola.
Expenditures of about $1.8 billion in the United States
related primarily to various development activities in the Gulf
of Mexico and the mid-continent region. In Asia, expendi-
tures during the year totaled $1.7 billion, primarily related to
development projects in Thailand and Indonesia.
Proved Undeveloped Reserves for Five Years or
More Reserves that remain proved undeveloped for five or more
years are a result of several factors that affect optimal project
development and execution, such as the complex nature of the
development project in adverse and remote locations, physical
limitations of infrastructure or plant capacities that dictate project
timing, compression projects that are pending reservoir pressure
declines, and contractual limitations that dictate production levels.
At year-end 2012, the company held approximately
1.7 billion BOE of proved undeveloped reserves that have
remained undeveloped for five years or more. The reserves are
held by consolidated and affiliated companies and the major-
ity of these reserves are in locations where the company has a
proven track record of developing major projects.
78 Chevron Corporation 2012 Annual Report
In Africa, the majority of the 300 million BOE is related
to deepwater and natural gas developments in Nigeria.
Major Nigerian deepwater development projects include
Agbami, which started production in 2008 and has ongoing
development activities to maintain full utilization of infra-
structure capacity, and the Usan development, which started
production in 2012. Also in Nigeria, various fields and
infrastructure associated with the Escravos Gas Projects are
currently under development.
In Asia, approximately 200 million BOE remain clas-
sified as proved undeveloped after five years. The majority
relate to ongoing development activities in the Pattani Field
(Thailand) and the Malampaya Field (Philippines) that are
scheduled to maintain production within contractual and
infrastructure constraints.
In Australia, approximately 100 million BOE remain
classified as proved undeveloped due to a compression proj-
ect at the North West Shelf Venture, which is scheduled for
start-up in 2013.
Affiliated companies have approximately 1.0 billion BOE
of proved undeveloped reserves that have been recorded for
five years or more. The TCO affiliate in Kazakhstan accounts
for most of this amount. Production is constrained by plant
capacity limitations. In Venezuela, development drilling
continues at Hamaca to optimize utilization of upgrader
capacity.
Annually, the company assesses whether any changes
have occurred in facts or circumstances, such as changes to
development plans, regulations or government policies, that
would warrant a revision to reserve estimates. For 2012, this
assessment did not result in any material changes in reserves
classified as proved undeveloped. Over the past three years,
the ratio of proved undeveloped reserves to total proved
reserves has ranged between 37 percent and 46 percent. The
consistent completion of major capital projects has kept the
ratio in a narrow range over this time period.
Proved Reserve Quantities At December 31, 2012,
proved reserves for the company were 11.3 billion BOE.
(Refer to the term “Reserves” on page 8 for the definition of
oil-equivalent reserves.) Approximately 17 percent of the total
reserves were located in the United States.
Aside from the TCO affiliate’s Tengiz Field in
Kazakhstan, no single property accounted for more than 5
percent of the company’s total oil-equivalent proved reserves.
About 20 other individual properties in the company’s
portfolio of assets each contained between 1 percent and
5 percent of the company’s oil-equivalent proved reserves,
which in the aggregate accounted for 45 percent of the com-
pany’s total oil-equivalent proved reserves. These properties
were geographically dispersed, located in the United States,
Canada, South America, Africa, Asia and Australia.
Table V Reserve Quantity Information – Continued
In the United States, total proved reserves at year-end
2012 were 2.0 billion BOE. California properties accounted
for 32 percent of the U.S. reserves, with most classified as
heavy oil. Because of heavy oil’s high viscosity and the need
to employ enhanced recovery methods, most of the com-
pany’s heavy-oil fields in California employ a continuous
steamflooding process. The Gulf of Mexico region contains
26 percent of the U.S. reserves and production operations are
mostly offshore. Other U.S. areas represent the remaining 42
percent of U.S. reserves. For production of crude oil, some
fields utilize enhanced recovery methods, including water-
flood and CO2 injection.
For the three years ending December 31, 2012, the pat-
tern of net reserve changes shown in the following tables are
not necessarily indicative of future trends. Apart from acqui-
sitions, the company’s ability to add proved reserves is
affected by, among other things, events and circumstances
that are outside the company’s control, such as delays in gov-
ernment permitting, partner approvals of development plans,
changes in oil and gas prices, OPEC constraints, geopolitical
uncertainties, and civil unrest.
The company’s estimated net proved reserves of crude
oil, condensate, natural gas liquids and synthetic oil and
changes thereto for the years 2010, 2011 and 2012 are shown
in the table below. The company’s estimated net proved
reserves of natural gas are shown on page 81.
Net Proved Reserves of Crude Oil, Condensate, Natural Gas Liquids and Synthetic Oil
Millions of barrels
Reserves at January 1, 2010
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production
Reserves at December 31, 20104
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production
Reserves at December 31, 20114
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production
Reserves at December 31, 20124
U.S.
1,361
63
11
19
–
(1)
(178)
1,275
63
6
140
2
(5)
(170)
1,311
104
24
77
10
(1)
(166)
1,359
Other
Americas1
Africa
Asia
Australia
Synthetic
Oil2
Europe
Total
TCO
Synthetic
Oil
Other3
Consolidated Companies
Affiliated Companies
Total
Consolidated
and Affiliated
Companies
104
1,246
1,171
98
170
460
4,610
1,946
266
151
6,973
12
3
19
–
–
(30)
108
4
4
30
–
–
(33)
113
20
8
101
–
–
(19)
223
17
58
9
–
–
(162)
1,168
60
48
34
–
–
(155)
1,155
66
30
30
–
–
(151)
1,130
(26)
2
16
11
–
(161)
1,013
25
–
4
–
–
(148)
894
97
6
2
–
(15)
(147)
837
3
–
–
–
–
(13)
88
(2)
–
65
–
(1)
(10)
140
4
–
7
–
(7)
(10)
134
19
–
–
–
–
(37)
152
15
–
26
–
–
(34)
159
16
9
–
–
–
(27)
157
15
–
–
–
–
(9)
466
32
–
–
40
–
(15)
523
6
–
–
–
–
(16)
513
103
74
63
11
(1)
(590)
4,270
197
58
299
42
(6)
(565)
4,295
313
77
217
10
(23)
(536)
4,353
(33)
–
–
–
–
(93)
1,820
28
–
–
–
–
(89)
1,759
59
–
–
–
–
(86)
1,732
–
–
–
–
–
(10)
256
–
–
–
–
–
(12)
244
(6)
–
–
–
–
(6)
232
12
3
–
–
–
(9)
157
10
–
–
–
–
(10)
157
24
–
1
–
–
(18)
164
82
77
63
11
(1)
(702)
6,503
235
58
299
42
(6)
(676)
6,455
390
77
218
10
(23)
(646)
6,481
1 Ending reserve balances in North America were 121, 13 and 14 and in South America were 102, 100 and 94 in 2012, 2011 and 2010, respectively.
2 Reserves associated with Canada.
3 Ending reserve balances in Africa were 41, 38 and 36 and in South America were 123, 119 and 121 in 2012, 2011 and 2010, respectively.
4 Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page 8 for the definition of a PSC). PSC-related reserve quantities are
20 percent, 22 percent and 24 percent for consolidated companies for 2012, 2011 and 2010, respectively.
Chevron Corporation 2012 Annual Report 79
Table V Reserve Quantity Information – Continued
Noteworthy amounts in the categories of liquids proved
reserve changes for 2010 through 2012 are discussed below:
Revisions In 2010, net revisions increased reserves 82
million barrels. For consolidated companies, improved reser-
voir performance accounted for a majority of the 63 million
barrel increase in the United States. Increases in the other
regions were partially offset by Asia, which decreased as a
result of the effect of higher prices on entitlement volumes in
Kazakhstan. For affiliated companies, the price effect on enti-
tlement volumes at TCO decreased reserves by 33 million
barrels.
In 2011, net revisions increased reserves 235 million
barrels. For consolidated companies, improved reservoir
performance accounted for a majority of the 63 million bar-
rel increase in the United States. In Africa, improved field
performance drove the 60 million barrel increase. In Asia,
increases from improved reservoir performance were partially
offset by the effects of higher prices on entitlement volumes.
Synthetic oil reserves in Canada increased by 32 million bar-
rels, primarily due to geotechnical revisions. For affiliated
companies, improved facility and reservoir performance was
partially offset by the price effect on entitlement volumes at
TCO.
In 2012, net revisions increased reserves 390 million
barrels. Improved field performance and drilling associated
with Gulf of Mexico projects accounted for the majority of
the 104 million barrel increase in the United States. In Asia,
drilling results across numerous assets drove the 97 million
barrel increase. Improved field performance from various
Nigeria and Angola producing assets was primarily respon-
sible for the 66 million barrel increase in Africa. Improved
plant efficiency for the TCO affiliate was responsible for a
large portion of the 59 million barrel increase.
Improved Recovery In 2010, improved recovery
increased volumes by 77 million barrels. Reserves in Africa
increased 58 million barrels due primarily to secondary recov-
ery performance in Nigeria.
In 2011, improved recovery increased volumes by
58 million barrels. Reserves in Africa increased 48 million
barrels due primarily to secondary recovery performance in
Nigeria.
In 2012, improved recovery increased reserves by 77 mil-
lion barrels, primarily due to secondary recovery performance
in Africa and in Gulf of Mexico fields in the United States.
Extensions and Discoveries In 2010, extensions and dis-
coveries increased reserves 63 million barrels. The United States
and Other Americas each increased reserves 19 million barrels,
and Asia increased reserves 16 million barrels. No single area in
the United States was individually significant. Drilling activ-
ity in Argentina and Brazil accounted for the majority of the
increase in Other Americas. In Asia, the increase was primarily
related to activity in Azerbaijan.
In 2011, extensions and discoveries increased reserves 299
million barrels. In the United States, additions related to two
Gulf of Mexico projects resulted in the majority of the 140
million barrel increase. In Australia, the Wheatstone Project
increased liquid volumes 65 million barrels. Africa and Other
Americas increased reserves 34 million and 30 million barrels,
respectively, following the start of new projects in these areas.
In Europe, a project in the United Kingdom increased reserves
26 million barrels.
In 2012, extensions and discoveries increased reserves 218
million barrels. In Other Americas, extensions and discover-
ies increased reserves 101 million barrels primarily due to the
initial booking of the Hebron project in Canada. In the United
States, additions at several Gulf of Mexico projects and drilling
activity in the mid-continent region were primarily responsible
for the 77 million barrel increase.
Purchases In 2011, purchases increased worldwide liq-
uid volumes 42 million barrels. The acquisition of additional
acreage in Canada increased synthetic oil reserves 40 million
barrels.
80 Chevron Corporation 2012 Annual Report
Table V Reserve Quantity Information – Continued
Net Proved Reserves of Natural Gas
Billions of cubic feet (BCF)
Reserves at January 1, 2010
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production3
Reserves at December 31, 20104
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production3
Reserves at December 31, 20114
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production3
Reserves at December 31, 20124
U.S.
2,698
220
1
36
3
(7)
(479)
2,472
217
–
287
1,231
(95)
(466)
3,646
318
5
166
33
(6)
(440)
3,722
Other
Americas1
1,985
4
1
4
–
–
(179)
1,815
(4)
1
13
–
–
(161)
1,664
(77)
–
34
–
–
(146)
1,475
Africa
3,021
(20)
–
–
–
–
(57)
2,944
39
–
290
–
–
(77)
3,196
(30)
–
2
–
–
(87)
3,081
Consolidated Companies
Affiliated Companies
Asia
Australia
Europe
Total
7,860
6,245
344
22,153
(31)
–
59
4
–
(699)
7,193
196
–
46
2
(2)
(714)
6,721
(22)
–
–
–
–
(167)
6,056
(107)
–
4,035
–
(77)
(163)
9,744
1,007
1
50
–
(93)
(819)
6,867
358
–
747
–
(439)
(158)
10,252
46
–
11
–
–
(126)
275
74
–
9
–
–
(100)
258
84
2
–
–
–
(87)
257
197
2
110
7
(7)
(1,707)
20,755
415
1
4,680
1,233
(174)
(1,681)
25,229
1,660
8
999
33
(538)
(1,737)
25,654
TCO
2,833
(324)
–
–
–
–
(123)
2,386
(21)
–
–
–
–
(114)
2,251
158
–
–
–
–
(110)
2,299
Other2
1,063
56
–
–
–
–
(9)
1,110
103
–
–
–
–
(10)
1,203
37
–
12
–
–
(10)
1,242
Total
Consolidated
and Affiliated
Companies
26,049
(71)
2
110
7
(7)
(1,839)
24,251
497
1
4,680
1,233
(174)
(1,805)
28,683
1,855
8
1,011
33
(538)
(1,857)
29,195
1 Ending reserve balances in North America and South America were 49, 19, 21 and 1,426, 1,645, 1,794 in 2012, 2011 and 2010, respectively.
2 Ending reserve balances in Africa and South America were 1,068, 1,016, 953 and 174, 187, 157 in 2012, 2011 and 2010, respectively.
3 Total “as sold” volumes are 1,647 BCF, 1,591 BCF and 1,644 BCF for 2012, 2011 and 2010, respectively.
4 Includes reserve quantities related to production-sharing contracts (PSC) (refer to page 8 for the definition of a PSC). PSC-related reserve quantities are 21 percent,
21 percent and 29 percent for consolidated companies for 2012, 2011 and 2010, respectively.
Noteworthy amounts in the categories of natural gas
proved-reserve changes for 2010 through 2012 are dis-
cussed below:
Revisions In 2010, net revisions decreased reserves by 71
BCF. For consolidated companies, a net increase in the United
States of 220 BCF, primarily in the mid-continent area and the
Gulf of Mexico, was the result of a number of small upward
revisions related to improved reservoir performance and drill-
ing activity, none of which were individually significant. The
increase was partially offset by downward revisions due to the
impact of higher prices on entitlement volumes in Asia. For
equity affiliates, a downward revision of 324 BCF at TCO was
due to the price effect on entitlement volumes and a change in
the variable-royalty calculation. This decline was partially offset
by the recognition of additional reserves related to the Angola
LNG project.
In 2011, net revisions increased reserves 497 BCF. For
consolidated companies, improved reservoir performance
accounted for a majority of the 217 BCF increase in the United
States. In Asia, a net increase of 196 BCF was driven by devel-
opment drilling and improved field performance in Thailand,
partially offset by the effects of higher prices on entitlement
volumes in Kazakhstan. For affiliated companies, ongoing
reservoir assessment resulted in the recognition of additional
reserves related to the Angola LNG project. At TCO, improved
facility and reservoir performance was more than offset by the
price effect on entitlement volumes.
Chevron Corporation 2012 Annual Report 81
Table V Reserve Quantity Information – Continued
In 2012, net revisions increased reserves 1,855 BCF. A
net increase of 1,007 BCF in Asia was primarily due to devel-
opment drilling and additional compression in Bangladesh,
and drilling results and improved field performance in
Thailand. In Australia, updated reservoir data interpretation
based on additional drilling at the Gorgon Project drove
the 358 BCF increase. Drilling results from activities in the
Marcellus Shale were responsible for the majority of the 318
BCF increase in the United States.
Extensions and Discoveries In 2011, extensions and
discoveries increased reserves 4,680 BCF. In Australia, the
Wheatstone Project accounted for the 4,035 BCF in addi-
tions. In Africa, the start of a new natural gas development
project in Nigeria resulted in the 290 BCF increase. In the
United States, development drilling accounted for the major-
ity of the 287 BCF increase.
In 2012, extensions and discoveries increased reserves by
1,011 BCF. The increase of 747 BCF in Australia was primar-
ily related to positive drilling results at the Gorgon Project.
Purchases In 2011, purchases increased reserves
1,233 BCF. In the United States, acquisitions in the
Marcellus Shale increased reserves 1,230 BCF.
Sales In 2011, sales decreased reserves 174 BCF. In
Australia, the Wheatstone Project unitization and equity
sales agreements reduced reserves 77 BCF. In the United
States, sales in Alaska and other smaller fields reduced
reserves 95 BCF.
In 2012, sales decreased reserves by 538 BCF. Sales
of a portion of the company’s equity interest in the
Wheatstone Project were responsible for the 439 BCF
reserves reduction in Australia.
82 Chevron Corporation 2012 Annual Report
Table VI Standardized Measure of Discounted Future Net Cash
Flows Related to Proved Oil and Gas Reserves
The standardized measure of discounted future net cash
flows, related to the preceding proved oil and gas reserves, is
calculated in accordance with the requirements of the FASB.
Estimated future cash inflows from production are computed
by applying 12-month average prices for oil and gas to year-end
quantities of estimated net proved reserves. Future price changes
are limited to those provided by contractual arrangements in exis-
tence at the end of each reporting year. Future development and
production costs are those estimated future expenditures neces-
sary to develop and produce year-end estimated proved reserves
based on year-end cost indices, assuming continuation of year-end
economic conditions, and include estimated costs for asset retire-
ment obligations. Estimated future income taxes are calculated
by applying appropriate year-end statutory tax rates. These rates
reflect allowable deductions and tax credits and are applied to
estimated future pretax net cash flows, less the tax basis of related
assets. Discounted future net cash flows are calculated using
10 percent midperiod discount factors. Discounting requires a
year-by-year estimate of when future expenditures will be incurred
and when reserves will be produced.
The information provided does not represent management’s
estimate of the company’s expected future cash flows or value of
proved oil and gas reserves. Estimates of proved-reserve quantities
are imprecise and change over time as new information becomes
available. Moreover, probable and possible reserves, which may
become proved in the future, are excluded from the calculations.
The valuation prescribed by the FASB requires assumptions as to
the timing and amount of future development and production
costs. The calculations are made as of December 31 each year and
should not be relied upon as an indication of the company’s future
cash flows or value of its oil and gas reserves. In the following
table, “Standardized Measure Net Cash Flows” refers to the stan-
dardized measure of discounted future net cash flows.
Table VI – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves
Millions of dollars
At December 31, 2012
Future cash inflows from production1
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10 percent midyear annual discount
for timing of estimated cash flows
Standardized Measure
Net Cash Flows
At December 31, 20112
Future cash inflows from production1
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10 percent midyear annual discount
for timing of estimated cash flows
Standardized Measure
Net Cash Flows
At December 31, 20102
Future cash inflows from production1
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10 percent midyear annual discount
for timing of estimated cash flows
Standardized Measure
Net Cash Flows
Other
Americas
U.S.
Africa
Asia
Australia
Europe
Total
Consolidated Companies
Total
Affiliated Companies Consolidated
and Affiliated
Companies
Other
TCO
$ 139,856 $ 72,548
(46,173) (26,450)
(11,192) (11,925)
(9,902)
(31,647)
$ 122,189 $ 121,849
(35,713)
(24,591)
(17,275)
(14,601)
(30,763)
(48,683)
$ 134,009
(18,340)
(24,923)
(27,224)
$ 19,653 $ 610,104 $ 169,966 $ 47,496 $ 827,566
(19,899) (212,019)
(32,085)
(3,710)
(12,355)
(97,927)
(13,363) (204,829)
(37,658)
(8,768) (160,035)
(1,946)
(81,862)
(5,589) (153,808)
50,844
24,271
34,314
38,098
63,522
3,350 214,399
87,868
10,524
312,791
(21,416) (15,906)
(12,430)
(13,033)
(40,450)
(860) (104,095)
(47,534)
(5,644) (157,273)
$ 29,428 $ 8,365
$ 21,884 $ 25,065
$ 23,072
$ 2,490 $ 110,304 $ 40,334 $ 4,880 $ 155,518
$ 143,633 $ 63,579
(39,523) (22,856)
(9,345)
(11,272)
(9,121)
(34,050)
$ 124,077 $ 124,972
(35,579)
(22,703)
(15,035)
(10,695)
(33,884)
(53,103)
$ 113,773
(15,411)
(29,489)
(20,661)
$ 19,704 $ 589,738 $ 171,588 $ 42,212 $ 803,538
(19,430) (193,873)
(30,904)
(10,778)
(90,126)
(10,833) (205,579)
(36,698)
(143,539)
(76,512)
(158,048)
(7,467)
(676)
(7,229)
(2,836)
58,788
22,257
37,576
40,474
48,212
4,332 211,639
93,208
9,113
313,960
(25,013) (15,082)
(13,801)
(14,627)
(35,051)
(1,117)
(104,691)
(51,547)
(4,883) (161,121)
$ 33,775 $ 7,175
$ 23,775 $ 25,847
$ 13,161
$
3,215 $ 106,948 $ 41,661 $ 4,230 $ 152,839
$ 101,281 $ 48,068
(36,609) (22,118)
(6,953)
(7,337)
(6,661)
(20,307)
$ 90,402 $ 101,553
(19,591)
(30,793)
(12,239) (11,690)
(26,355)
(34,405)
$ 52,635
(9,191)
(13,160)
(9,085)
$ 13,618 $ 407,557 $ 124,970 $ 31,188 $ 563,715
(4,172) (150,620)
(22,304)
(8,777)
(62,442)
(2,254)
(12,919) (140,963)
(26,524)
(124,144)
(51,411)
(101,520)
(5,842)
(708)
(4,031)
37,704
11,660
24,167
32,715
21,199
3,037 130,482
67,365
11,843
209,690
(13,218)
(6,751)
(9,221)
(12,287)
(15,282)
(699)
(57,458)
(37,015)
(6,574) (101,047)
$ 24,486 $ 4,909
$ 14,946 $ 20,428
$ 5,917
$
2,338 $ 73,024 $ 30,350 $ 5,269 $ 108,643
1 Based on 12-month average price.
2 2011 and 2010 conformed to 2012 presentation.
Chevron Corporation 2012 Annual Report 83
Table VII Changes in the Standardized Measure of Discounted
Future Net Cash Flows From Proved Reserves
The changes in present values between years, which can
be significant, reflect changes in estimated proved-reserve
quantities and prices and assumptions used in forecast-
ing production volumes and costs. Changes in the timing
of production are included with “Revisions of previous
quantity estimates.”
Table VII – Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves
Millions of dollars
Consolidated Companies
Affiliated Companies
$
$
50,276
(39,047)
12,042
513
(47)
5,194
9,704
43,887
8,391
(17,889)
22,748
73,024
(52,338)
13,869
1,212
(803)
12,288
16,025
61,428
11,943
(29,700)
33,924
106,948
(49,094)
18,013
376
(1,630)
11,303
23,556
(19,179)
18,026
1,985
3,356
$ 110,304
$
$
$
$
$
27,236
(6,377)
572
–
–
63
1,113
14,429
3,797
(5,214)
8,383
35,619
(8,679)
729
–
–
–
923
15,979
5,048
(3,728)
10,272
45,891
(7,708)
942
–
–
106
3,759
(2,266)
6,322
(1,832)
(677)
45,214
Present Value at January 1, 2010*
Sales and transfers of oil and gas produced net of production costs
Development costs incurred
Purchases of reserves
Sales of reserves
Extensions, discoveries and improved recovery less related costs
Revisions of previous quantity estimates
Net changes in prices, development and production costs
Accretion of discount
Net change in income tax
Net change for 2010
Present Value at December 31, 20101
Sales and transfers of oil and gas produced net of production costs
Development costs incurred
Purchases of reserves
Sales of reserves
Extensions, discoveries and improved recovery less related costs
Revisions of previous quantity estimates
Net changes in prices, development and production costs
Accretion of discount
Net change in income tax
Net change for 2011
Present Value at December 31, 2011
Sales and transfers of oil and gas produced net of production costs
Development costs incurred
Purchases of reserves
Sales of reserves
Extensions, discoveries and improved recovery less related costs
Revisions of previous quantity estimates
Net changes in prices, development and production costs
Accretion of discount
Net change in income tax
Net change for 2012
Present Value at December 31, 2012
* 2011 and 2010 conformed to 2012 presentation.
84 Chevron Corporation 2012 Annual Report
Total
Consolidated
and Affiliated
Companies
$
77,512
(45,424)
12,614
513
(47)
5,257
10,817
58,316
12,188
(23,103)
31,131
$ 108,643
(61,017)
14,598
1,212
(803)
12,288
16,948
77,407
16,991
(33,428)
44,196
$ 152,839
(56,802)
18,955
376
(1,630)
11,409
27,315
(21,445)
24,348
153
2,679
$ 155,518
Chevron History
1879
Incorporated in San Francisco,
California, as the Pacific Coast
Oil Company.
1900
Acquired by the West Coast
operations of John D. Rockefeller’s
original Standard Oil Company.
1911
Emerged as an autonomous
entity — Standard Oil Company
(California) — following U.S.
Supreme Court decision to divide
the Standard Oil conglomerate
into 34 independent companies.
1926
Acquired Pacific Oil Company
to become Standard Oil Company
of California (Socal).
1936
Formed the Caltex Group of
Companies, jointly owned by
Socal and The Texas Company
(later became Texaco), to combine
Socal’s exploration and production
interests in the Middle East and
Indonesia and provide an outlet for
crude oil through The Texas Company’s
marketing network in Africa and Asia.
1947
Acquired Signal Oil Company,
obtaining the Signal brand name
and adding 2,000 retail stations
in the western United States.
1961
Acquired Standard Oil Company
(Kentucky), a major petroleum
products marketer in five south-
eastern states, to provide outlets
for crude oil from southern
Louisiana and the U.S. Gulf of
Mexico, where the company
was a major producer.
1984
Acquired Gulf Corporation — nearly
doubling the size of crude oil and
natural gas activities — and gained
significant presence in industrial
chemicals, natural gas liquids and
coal. Changed name to Chevron
Corporation to identify with the
name under which most products
were marketed.
1988
Purchased Tenneco Inc.’s U.S. Gulf
of Mexico crude oil and natural gas
properties, becoming one of the
largest U.S. natural gas producers.
1993
Formed Tengizchevroil, a joint
venture with the Republic of
Kazakhstan, to develop and produce
the giant Tengiz Field, becoming the
first major Western oil company to
enter newly independent Kazakhstan.
1999
Acquired Rutherford-Moran Oil
Corporation. This acquisition provided
inroads to Asian natural gas markets.
2001
Merged with Texaco Inc. and
changed name to ChevronTexaco
Corporation. Became the second-
largest U.S.-based energy company.
2002
Relocated corporate headquarters
from San Francisco, California, to
San Ramon, California.
2005
Acquired Unocal Corporation, an
independent crude oil and natural
gas exploration and production
company. Unocal’s upstream assets
bolstered Chevron’s already-strong
position in the Asia-Pacific, U.S. Gulf
of Mexico and Caspian regions.
Changed name to Chevron
Corporation to convey a clearer,
stronger and more unified presence
in the global marketplace.
2011
Acquired Atlas Energy, Inc., an
independent U.S. developer and
producer of shale gas resources.
The acquired assets provide a
targeted, high-quality core
acreage position primarily
in the Marcellus Shale.
Chevron Corporation 2012 Annual Report 85
Board of Directors
John S. Watson, 56
Chairman of the Board and Chief Executive Officer
since 2010. Previously he was elected a Director and
Vice Chairman in 2009; Executive Vice President,
Strategy and Development; Corporate Vice President
and President, Chevron International Exploration and
Production Company; Vice President and Chief Financial
Officer; and Corporate Vice President, Strategic Planning.
He is a member of the Board of Directors and the
Executive Committee of the American Petroleum
Institute. Joined Chevron in 1980.
George L. Kirkland, 62
Vice Chairman of the Board since 2010 and Executive
Vice President of Upstream and Gas since 2005. In
addition to Board responsibilities, he is responsible
for global exploration, production and gas activities.
Previously Corporate Vice President and President,
Chevron Overseas Petroleum Inc., and President, Chevron
U.S.A. Production Company. Joined Chevron in 1974.
Robert E. Denham, 67
Lead Director since 201 1 and a Director since 2004.
He is a Partner in the law firm of Munger, Tolles & Olson
LLP. Previously he was Chairman and Chief Executive
Officer of Salomon Inc. He is a Director of The New
York Times Company; Oaktree Capital Group, LLC;
Fomento Económico Mexicano, S.A. de C.V.; and UGL
Limited. (3, 4)
Linnet F. Deily, 67
Director since 2006. She served as a Deputy U.S. Trade
Representative and U.S. Ambassador to the World
Trade Organization. Previously she was Vice Chairman
of Charles Schwab Corporation. She is a Director of
Honeywell International Inc. (2, 4)
Alice P. Gast, 54
Director since 2012. She is President of Lehigh University
in Bethlehem, Pennsylvania. Previously she served as
Vice President for Research, Associate Provost and
Robert T. Haslam Chair in Chemical Engineering at the
Massachusetts Institute of Technology. (1)
Enrique Hernandez, Jr., 57
Director since 2008. He is Chairman, Chief Executive
Officer and President of Inter-Con Security Systems, Inc.,
a provider of security and facility support services to
government, utilities and industrial customers. He is
a Director of McDonald’s Corporation; Nordstrom, Inc.;
and Wells Fargo & Company. (1)
Charles W. Moorman, 61
Director since 2012. He is Chairman of the Board, Chief
Executive Officer and President of Norfolk Southern
Corporation, a freight transportation company.
Previously he served as Senior Vice President of
Corporate Planning and Services at Norfolk Southern.
(2, 4)
Kevin W. Sharer, 65
Director since 2007. He is a Senior Lecturer of Business
Administration at the Harvard Business School and is
retired Chairman of the Board and Chief Executive Officer
of Amgen Inc., a global biotechnology medicines company.
Previously he was President and Chief Operating Officer
of Amgen. He is a Director of Northrop Grumman
Corporation. (3, 4)
John G. Stumpf, 59
Director since 2010. He is Chairman of the Board,
Chief Executive Officer and President of Wells Fargo
& Company, a nationwide, diversified, community-based
financial services company. Previously he served as
Group Executive Vice President of Community Banking
at Wells Fargo. He is a Director of Target Corporation. (1)
Ronald D. Sugar, 64
Director since 2005. He is retired Chairman of the
Board and Chief Executive Officer of Northrop Grumman
Corpo ration, a global defense and technology company.
Pre viously he was President and Chief Operating Officer
of Northrop Grumman. He is a Director of Amgen Inc.,
Air Lease Corporation and Apple Inc. (1)
Carl Ware, 69
Director since 2001. He is a retired Executive Vice
President of The Coca-Cola Company, a manufacturer
of beverages. Previously he was a Senior Adviser to the
Chief Executive Officer of The Coca-Cola Company and
an Executive Vice President, Global Public Affairs and
Administration, for The Coca-Cola Company. He is a
Director of Cummins Inc. (3, 4)
Retired Director
Chuck Hagel, a Director since 2010, resigned effective February 26, 2013. He has joined the
Obama administration as Secretary of Defense. He served as a U.S. Senator from Nebraska
from 1997 to 2009 and participated in numerous committees, including Foreign Relations;
Banking, Housing and Urban Affairs; Intelligence; and Energy and Natural Resources. He also
was a Distinguished Professor at Georgetown University and the University of Nebraska at
Omaha. (2, 3)
Committees of the Board
1 ) Audit: Ronald D. Sugar, Chair
2) Public Policy: Linnet F. Deily, Chair
3) Board Nominating and Governance:
Robert E. Denham, Chair
4) Management Compensation: Carl Ware, Chair
86 Chevron Corporation 2012 Annual Report
Corporate Officers
Lydia I. Beebe, 60
Corporate Secretary and Chief Governance Officer
since 1995. Responsible for providing advice and counsel
to the Board of Directors and senior management on
corporate governance matters and managing the
Corporate Governance function. Previously Senior
Manager, Chevron Tax Department. Joined Chevron
in 1977.
Paul V. Bennett, 59
Vice President and Treasurer since 2011. Responsible
for banking, financing, cash management, insurance,
pension investments, and credit and receivables activi-
ties corporatewide. Previously Vice President, Finance,
Downstream and Chemicals. Serves on the Board of
Directors of GS Caltex. Joined the company in 1980.
James R. Blackwell, 54
Executive Vice President, Technology and Services,
since 2011. Responsible also for major capital project
management, procurement, and other corporate
operating and support functions. Previously President,
Chevron Asia Pacific Exploration and Production
Company; Managing Director, Chevron Southern
Africa Strategic Business Unit; and President, Chevron
Pipe Line Company. Joined the company in 1980.
Matthew J. Foehr, 55
Vice President and Comptroller since 2010. Responsible
for corporatewide accounting, financial reporting and
analysis, internal controls, and Finance Shared Services.
Previously Vice President, Finance, Global Upstream and
Gas, and Vice President, Finance, Global Downstream.
Joined Chevron in 1982.
Joseph C. Geagea, 53
Corporate Vice President and President, Chevron
Gas and Midstream, since 2012. Responsible for
commercializing the company’s natural gas resources,
supporting the development of new growth opportunities
worldwide, and overseeing shipping, pipeline, power and
natural gas trading operations. Previously Managing
Director, Chevron Asia South Ltd., Chevron Asia Pacific
Exploration and Production Company, and Vice President,
Upstream Capability, Chevron International Exploration
and Production Company. Joined the company in 1982.
Stephen W. Green, 55
Vice President, Policy, Government and Public Affairs,
since 2011. Responsible for U.S. and international govern-
ment relations, all aspects of communications, and the
company’s worldwide efforts to protect and enhance
its reputation. Previously President, Chevron Indonesia
Company and Managing Director, IndoAsia Business
Unit, Chevron Asia Pacific Exploration and Production
Company. Joined the company in 1998.
Joe W. Laymon, 60
Vice President, Human Resources, Medical and Security,
since 2008. Responsible for the company’s global human
resources, medical services and security functions.
Previously Group Vice President, Corporate Human
Resources and Labor Affairs, Ford Motor Company.
Joined the company in 2008.
Wesley E. Lohec, 53
Vice President, Health, Environment and Safety (HES),
since 2011. Responsible for HES strategic planning and
issues management, compliance assurance, emergency
response, and Chevron’s Environmental Management
Company. Previously Managing Director, Latin America,
Chevron Africa and Latin America Exploration and
Production Company. Joined the company in 1981.
Charles N. Macfarlane, 58
General Tax Counsel since 2010. Responsible for
directing Chevron’s worldwide tax activities. Previously
the company’s Assistant General Tax Counsel. Joined
Chevron in 1986.
John W. McDonald, 61
Vice President and Chief Technology Officer since
2008. Responsible for Chevron’s three technology com-
panies: Energy Technology, Information Technology and
Technology Ventures, and the research, development
and deployment of technology companywide. Previously
Corporate Vice President, Strategic Planning; President
and Managing Director, Chevron Upstream Europe,
Chevron Overseas Petroleum Inc.; and Vice President,
Gulf of Mexico Offshore Division, Texaco Exploration and
Production. Joined the company in 1975.
R. Hewitt Pate, 50
Vice President and General Counsel since 2009.
Responsible for directing the company’s worldwide
legal affairs. Previously Chair, Competition Practice,
Hunton & Williams LLP, Washington, D.C., and Assistant
Attorney General, Antitrust Division, U.S. Department
of Justice. Joined Chevron in 2009.
Jay R. Pryor, 55
Vice President, Business Development, since 2006.
Responsible for identifying and developing new, large-
scale upstream and downstream business opportunities,
including mergers and acquisitions. Previously Managing
Director, Nigeria/Mid-Africa Strategic Business Unit and
Chevron Nigeria Ltd., and Managing Director, Asia South
Business Unit and Chevron Offshore (Thailand) Ltd.
Joined Chevron in 1979.
Charles A. Taylor, 55
Vice President, Strategic Planning, since 2011.
Responsible for advising senior corporate executives in
setting strategic direction for the company, allocating
capital and other resources, and determining operat-
ing unit performance measures and targets. Previously
Corporate Vice President, Health, Environment and
Safety. Joined the company in 1980.
Michael K. Wirth, 52
Executive Vice President, Downstream and Chemicals,
since 2006. Responsible for worldwide manufacturing,
marketing, lubricants, supply and trading businesses,
chemicals and Oronite additives. Previously President,
Global Supply and Trading; President, Marketing, Asia/
Middle East/Africa Strategic Business Unit; and President,
Marketing, Caltex Corporation. Joined Chevron in 1982.
Patricia E. Yarrington, 57
Vice President and Chief Financial Officer since 2009.
Responsible for comptroller, tax, treasury, audit and
investor relations activities. Chairman of the San Francisco
Federal Reserve’s Board of Directors. Previously a
Director, Chevron Phillips Chemical Company LLC;
Corporate Vice President and Treasurer; Corporate
Vice President, Policy, Government and Public Affairs;
Corporate Vice President, Strategic Planning; President,
Chevron Canada Limited; and Comptroller, Chevron
Products Company. Joined Chevron in 1980.
Rhonda I. Zygocki, 55
Executive Vice President, Policy and Planning,
since 2011. Responsible for Strategic Planning; Health,
Environment and Safety; and Policy, Government and
Public Affairs. Previously Corporate Vice President, Policy,
Government and Public Affairs; Corporate Vice President,
Health, Environment and Safety; and Managing Director,
Chevron Australia Pty Ltd. Joined Chevron in 1980.
Executive Committee
John S. Watson, George L. Kirkland, James R. Blackwell,
R. Hewitt Pate, Michael K. Wirth, Patricia E. Yarrington and
Rhonda I. Zygocki. Lydia I. Beebe, Secretary.
Chevron Corporation 2012 Annual Report 87
Stockholder and Investor Information
Stock Exchange Listing
Chevron common stock is listed on
the New York Stock Exchange. The
symbol is “CVX.”
Stockholder Information
Questions about stock owner-
ship, changes of address, dividend
payments or direct deposit of
dividends should be directed to
Chevron ’s transfer agent and
registrar:
Computershare
P.O. Box 43006
Providence, RI 02940-3006
800 368 8357
www.computershare.com/investor
Overnight correspondence should
be mailed to:
Computershare
250 Royall Street
Canton, MA 02021-1011
The Computershare Investment Plan
features dividend reinvestment,
optional cash investments of $50 to
$100,000 a year and automatic stock
purchase.
Investor Information
Securities analysts, portfolio
managers and representatives of
financial institutions may contact:
Investor Relations
Chevron Corporation
6001 Bollinger Canyon Road, A3064
San Ramon, CA 94583-2324
925 842 5690
Email: invest@chevron.com
Notice
As used in this report, the term
“Chevron” and such terms as “the
company,” “the corporation,” “our,”
“we” and “us” may refer to one or
more of its consolidated subsidi-
aries or to all of them taken as a
whole. All of these terms are used
for convenience only and are not
intended as a precise description of
any of the separate companies, each
of which manages its own affairs.
Corporate Headquarters
6001 Bollinger Canyon Road
San Ramon, CA 94583-2324
925 842 1000
Dividend Payment Dates
Quarterly dividends on common
stock are paid, following declaration
by the Board of Directors, on or
about the 10th day of March, June,
September and December. Direct
deposit of dividends is available
to stockholders. For information,
contact Computershare. (See
Stockholder Information.)
Annual Meeting
The Annual Meeting of stock-
holders will be held at 8:00 a.m.,
Wednesday, May 29, 2013, at:
Chevron Corporation
6001 Bollinger Canyon Road
San Ramon, CA 94583-2324
Electronic Access
In an effort to conserve natural
resources and reduce the cost of
printing and shipping proxy materials
next year, we encourage stock holders
to register to receive these documents
via email and vote their shares on
the Internet. Stock holders of record
may sign up on our website, www.
icsdelivery.com/cvx/index.html,
for electronic access. Enrollment is
revocable until each year’s Annual
Meeting record date. Bene ficial
stockholders may be able to request
electronic access by contacting their
broker or bank, or Broadridge Financial
Solutions at: www.icsdelivery.com/
cvx/index.html.
88 Chevron Corporation 2012 Annual Report
CVX 2013 CRR FC Simulated Blind Emboss
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M
Y
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2012 Corporate Responsibility Report
2012 Annual Report
2012 Supplement to the Annual Report
2012 Corporate Responsibility Report
CVX_2012CR_Cov_v1.2_030313PRO.indd 2
3/8/13 3:28 PM
Publications and
Other news sources
The Annual Report, distributed in
April, summarizes the company’s
financial performance in the
preced ing year and provides an
overview of the company’s major
activities.
Chevron’s Annual Report on Form
10-K filed with the U.S. Securities
and Exchange Commission and the
Supplement to the Annual Report,
containing additional financial and
operating data, are available on the
company’s website, Chevron.com,
or copies may be requested by
writing to:
Comptroller’s Department
Chevron Corporation
6001 Bollinger Canyon Road, A3201
San Ramon, CA 94583-2324
The Corporate Responsibility
Report is available in May on the
company’s website, Chevron.com/
CorporateResponsibility, or a copy
may be requested by writing to:
Policy, Government and Public Affairs
Chevron Corporation
6101 Bollinger Canyon Road
BR1X3200
San Ramon, CA 94583-5177
Information about the company’s
social investments is available
in the second half of the year on
Chevron’s website, Chevron.com/
SocialInvestment.
Details of the company’s political
contributions for 20 1 2 are available
on the company’s website,
Chevron.com, or by writing to:
Policy, Government and Public Affairs
Chevron Corporation
6101 Bollinger Canyon Road
BR1X3400
San Ramon, CA 94583-5177
For additional information about
the company and the energy
industry, visit Chevron’s website,
Chevron.com. It includes articles,
news releases, speeches, quarterly
earnings information, the Proxy
Statement and the complete text of
this Annual Report.
This Annual Report contains forward-looking statements — identified by words such as “expects,” “intends,”
“projects,” etc. — that reflect management’s current estimates and beliefs, but are not guarantees of future
results. Please see “Cautionary Statement Relevant to Forward-Looking Information for the Purpose of
‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” on Page 9 for a discussion
of some of the factors that could cause actual results to differ materially.
PHOTOGRAPHY
Cover: Peter Cannon/GeoMedia; Inside Front Cover: Ken Childress Photography; Page 2: Eric Myer;
Page 6: Jim Karageorge.
PROduCed bY Policy, Government and Public Affairs and Comptroller’s Departments, Chevron Corporation
desIGn Design One — San Francisco, California
PRInTInG ColorGraphics — Los Angeles, California
Hold this QR code
to your smartphone
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Chevron Corporation
6001 Bollinger Canyon Road
San Ramon, CA 94583-2324 USA
www.chevron.com
© 2013 Chevron Corporation. All rights reserved.
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