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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) March 28, 2011

OCCIDENTAL PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	1-9210	95-4035997
(State or other jurisdiction	(Commission	(I.R.S. Employer
of incorporation)	File Number)	Identification No.)

10889 Wilshire Boulevard
Los Angeles, California		90024
(Address of principal executive offices)		(ZIP code)

Registrant’s telephone number, including area code:

(310) 208-8800

Check the appropriate box below if the Form 8-K is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions (see General Instruction A.2. below):

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure

Attached as Exhibit 99.1 is a presentation made by Stephen I. Chazen, Occidental’s President and Chief Operating Officer, in connection with the March 29, 2011, Howard Weil 39th Annual Energy Conference. The information in this Item 7.01 and Exhibit 99.1 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such filing.

Section 9 - Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits

(d)		Exhibits

99.1		Presentation dated March 29, 2011.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	OCCIDENTAL PETROLEUM CORPORATION
	(Registrant)


DATE: March 28, 2011	/s/ ROY PINECI
	Roy Pineci, Vice President, Controller
	and Principal Accounting Officer

EXHIBIT INDEX

99.1

Presentation dated March 29, 2011.

ex991-20110328.htm

EXHIBIT 99.1

Stephen I. Chazen

President and Chief Operating Officer

March 29, 2011

Occidental Petroleum Corporation

Howard Weil
39th Annual Energy Conference

	FY2010	FY2009
• Core Results	$4,664	$3,192
• Core EPS (diluted)	$5.72	$3.92

• Net Income	$4,530	$2,915
• Reported EPS (diluted)	$5.56	$3.58

• Oil and Gas production volumes (mboe/d) & excl. Argentina; +5.2%	706	671

• Capital Spending	$3,940	$3,245
• Cash Flow from Operations	$9,349	$5,807

• ROE	14.7%	10.3%
• ROCE	13.2%	9.6%

($ in millions, except EPS data)

See attached for GAAP reconciliation

Full Year 2010 Results - Summary

What Is Our Philosophy & Strategy?

Overriding Goal is to Maximize Total Shareholder Return

• We believe this can be achieved through a combination of:

• Growing our oil and gas production by 5 to 8% per year on
average over the long term;

• Allocating and deploying capital with a focus on achieving
strong financial returns (ROE and ROCE);

– Return Targets*

• Domestic - 15+%

• International - 20+%

• Consistent dividend growth, that is superior to that of our
peers.

*Assumes Moderate Product Prices

Low

Middle

Risk Factor

Exploratory

Commodity

Political

Engineering

Reinvestment

Financial

High

Level of Risk Acceptable to Occidental

Business Risk Factors

740 - 750

(15)

(7)

725

(1)

(7)

Previous 1Q11 Guidance

Libya & Yemen; and slower
capital spending in Iraq

Impact of weather in
Permian and Midcontinent

Oil price impact

(thousand boe/d)

Oil & Gas
Production

Oil & Gas
Sales

Note: Previous guidance excludes Argentina; includes maintenance shut-downs at Elk Hills and Dolphin, and partial impact of
acquired properties.

Adjusted 1Q11 Oil & Gas Production/Sales Guidance

(Percentage of Oxy’s worldwide proved oil reserves)

Note: excludes Argentina as the sale of this asset closed in February 2011.

Oil Reserves Concentrated in the U.S.

(Percentage of Oxy total company value)

Note: excludes Argentina as the sale of this asset closed in February 2011.

Standard Measure of Discounted Future Net Cash
Flows (SEC PV-10)

Worldwide Oil & Gas Producing Areas

Capital Spending - 2011 Outlook

• We expect capital spending for the total year 2011 to be
about $6.1 billion compared to the total 2010 capital of
$3.9 billion.

• Both amounts exclude Argentina and the Shah Field
Development Project.

• Oxy's share of the Shah Field development capital will
total about $4 billion over the next several years.

Capital Spending - 2011E vs. 2010 Actual

• Base 5 - 8% Growth

– CO2 in Permian

– Current California risked prospects

– Recent domestic properties acquisitions (Williston Basin, South
TX gas)

– Oman

– Iraq

• Upside from Existing Holdings

– New California conventional and unconventional prospects

– Permian exploration

– Rockies gas

• Additional opportunities from balance sheet and cash
generation

– Domestic properties acquisitions

– New Middle East projects (i.e. Shah gas field)

Oil & Gas Volume Growth Drivers

• Divestment of Oxy’s Argentine oil and gas operations to
Sinopec for after-tax proceeds of approximately $2.6 billion

• Oxy purchased oil and gas properties in South Texas and
North Dakota for about $3.2 billion

• Oxy increased its interest in General Partner (GP) ownership
in Plains All-American (PAA) by 13% to approximately 35%

• Oxy has acquired the remaining 50% joint venture interest in
the Elk Hills Power Plant from Sempra

• 21% increase in our common share dividend rate from $0.38
to $0.46 per quarter effective with the 4/15/2011 payment

Summary of Recent Transactions
(announced 12/10/10)

• These new acquisitions and the sale of Argentina will:

– be immediately accretive to our earnings, ROCE and cash flow after
capital;

– provide greater certainty in achieving both our short-term and long-term
average annual production growth outlook of 5 to 8%;

– increase the domestic weighting of our Oil and Gas operations;

– NOT materially alter the mix between our oil and natural gas reserves or
production.

• These properties, combined with other acquisitions completed
in 2010, will more than replace the production from Argentina.

• PAA is one of the largest operators of oil pipelines in North
America with operations in TX, CA, and ND, among other areas.

• PAA’s operations complement Oxy’s US oil and gas operations.

• Our outlook for improved free cash flow provided for the
substantial increase to our dividend.

Impact of Transactions

Oxy - Shell South Texas Assets Transaction

• 100k gross, 92.8k net acres

• Production ~200 mmcfe/d of
gas equivalent

• 360+ Bcfe proven developed
reserves

– ~840 Bcfe of identified add’l
resource potential

• Over 550 active wells

• LOE of $0.47 - 0.74 per Mcfe

• Condensate & NGLs are
~30% of total revenue

• High WI - 92% avg. and low
royalty, avg. NRI of 85%

• 2011 focus on higher
recovery infill and step-out
locations at Slick & McAllen
Ranch

• Good returns at current
NYMEX gas strip prices

• Purchased ~174,000 contiguous net acres in ND within the
southern extents of the Bakken and Three Forks Formations.

• Operated working interests avg. 63% with avg. NRI of ~83%.

• Net risked reserve potential in excess of 250 mmboe from the
Middle Bakken and Upper Three Forks Formations.

• Prospective across entire acreage position for Three Forks
and deeper objectives.

• Combined with existing Oxy assets in the Williston Basin, Oxy
now has interests in over 200k net acres producing ~6 mboe/d.

• Oxy expects to grow production in the Williston Basin to at
least 30 mboe/d over the next five years.

– Currently running 8 drilling rigs on our Bakken acreage with plans to
increase this to 12 rigs by the end of 2011

– Plan to drill at least 70 Bakken shale wells during 2011

Oxy - North Dakota Assets Transaction

NORTH DAKOTA

South Coteau

Nesson

Anticline

Elm Coulee

Field

Parshall-

Sanish

Fields

Russian Creek

Burke

Ward

McLean

Mercer

Stark

Oliver

Williams

Divide

Roosevelt

McKenzie

Mountrail

Dunn

Billings

Renville

Richland

Morton

Dawson

Golden

Valley

Other Notable Areas of
Williston Basin Production

Other Oxy Operated
Acreage

Oxy Acquisition Area

Burleigh

Sheridan

McHenry

Bottineau

Bismarck

Oxy North Dakota - Williston Basin

Permian Basin Overview

• Approximately 1.2 billion BOE of
proved reserves at year end 2010

• 2010 production of 197,000 boe/d

• Largest oil producer in Permian
(~16% share of total)

• Largest operator in Permian
(of 1,500+ operators)

• ~66% of Oxy’s Permian oil
production is from CO2 related
EOR projects

• Have another 2.5 BBOE of likely
recoverable resource

• 1.7 bcf/d (0.5 tcf/year) of CO2

• Ample supply of CO2 accelerates
project implementations

Permian - 2011 Program Summary

• 2011 Capital program ~$850 mm

• Plan to drill 300+ wells this year

• Average 13-rig program in 2011

• Drilling program is front-end
loaded to exploit quick
production first

• 130+ workover/maintenance rigs
operating, two-thirds more than a
year ago

• Extensive Wolfberry drilling
program, as well as
Delaware/Bone Springs sands

• Midstream — Completion of
Century Plant Train II

* $75 / Bbl Marker Price

Typical Permian CO2 Project Cost Structure

Los Angeles

Bakersfield

Oxy Acreage

California Overview

• Largest acreage holder in CA
with 1.6 mm acres, majority of
which are net mineral interests.

• ~768 mm BOE of proved
reserves at year end 2010, of
which 73% are oil.

• 2010 production of 139 mboe/d.

• 78% interest in the Elk Hills
Field — the largest producer of
gas and NGLs in CA.

• Currently operating 22 drilling
rigs in the state.

• Began construction of first new
gas processing plant in 2010;
plan to start building a second
plant in the next two years.

California - 2011 Program Summary

THUMS

(Long Beach)

Los Angeles

Elk Hills

Buena Vista

Oxy Properties

Ventura Basin

San Joaquin Basin

• 2011 Capital program ~$1.3
billion, up ~50% vs. 2010.

• Plan to drill 500+ new
development wells.

• Shifting our drilling to oil wells
which we expect to result in
higher oil production in 2011.

• Drill about 28 exploration wells
in 2011.

• ~50% of these wells will be for
conventional exploration.

• We expect that the exploration
activity will, at a minimum,
create more unconventional
drilling locations.

• We have ~520 geologically
viable (so-called de-risked)
shale drilling locations in CA
excluding traditional Elk Hills.

• Of these, ~250 are both outside
of Elk Hills proper and the Kern
County Discovery Area.

• Based on a conservative view
of the permitting process, we
expect to drill 107 shale wells
outside Elk Hills proper in 2011.

• As additional permits become
available, the level of drilling
activity would rise this year.

California Unconventional “Shale” Program

Play	Depth (ft)	Thickness (ft)	Porosity (%)	Permeability (mD)	TOC (%)
CA “Shales”	3,500’ - 16,000’	500’ - 3,500’	5 - 30%	<0.0001 - 2	0.1 - 12%
Bakken	7,000’ - 11,000’	20’ - 100’	3 - 12%	0.05 - 0.5	2 - 18%
Eagle Ford	8,000’ - 14,000’	75’ - 300’	3 - 15%	<0.0001 - .003	0.6 - 7%

California “Shale” Summary and Play
Comparison

• ~870,000 acres are within most prospective “shale” plays

• Oxy’s average NRI ~95%

• Identified 15 areas to appraise (5 - 10% of total acreage)

– Initially target 1 to 2 areas including Kern County discovery

– Average IP 400 - 800 boepd; Production range from 100 to 1,000 boepd

– Average EUR 400 - 700 Mboe; 10-acre spacing

• In 10 years CA “shale” could become Oxy’s largest business unit

Operating
Cash Flow
from
Continuing
Operations
$9,100

(excluding
Argentina)

Beginning
Cash

$1,200
12/31/09

($ in millions)

– Free cash flow from continuing operations after capex and dividends
but before acquisition activity and debt retirements was ~$4.3 billion.

See attached for GAAP reconciliation

Summary of Full Year 2010 Cash Flow

1. Base/Maintenance Capital

2. Dividends

3. Growth Capital

4. Acquisitions

5. Share Repurchase

Cash Flow Priorities

F&D Costs
Actual as a % of
6:1 * Prices ** WTI Price

* Oil / Gas Energy Content (Industry convention)
** Gas converted to BOE @ WTI Oil Price / NYMEX Gas Price

Finding & Development Costs per Barrel

2010 $20.25 $24.18 30%

3-Year Average $16.38 $20.25 25%
(2008 - 2010)

5-Year Average $16.66 $19.52 26%
(2006 - 2010)

10-Year Average $12.22 $13.48 24%
(2001 - 2010)

See attached for GAAP reconciliation

Net Income Return on Assets

U.S. 16%

International 35%

Total E&P 21%

Cash Flow* Return on Assets

U.S. 24%

International 53%

Total E&P 31%

* Net Income + DD&A

5 Year Average

Return on Assets

See attached for GAAP reconciliation

(2006 - 2010)

Dividend Growth

Annual dividend to increase to $1.84 per share or 21% effective with the 4/15/11 payment

• Company’s core business is acquiring assets that can
provide future growth through improved recovery.

– Foreign contracts

– Domestic add-ons

– Small incremental additions to production in short term

• Generate returns of at least 15% in the US and 20% overseas.

• Overall average finding & development costs of less than
25% of selling price.

• Even with the additional capital shown, program will
generate a significant amount of free cash flow.

• Acquisitions are measured against reinvesting in the existing
business with the goal of enhancing company value.

• Large number of opportunities over 5-year period.

Acquisition Strategy

• 5 - 8% base annual production growth

• Opportunity for additional volume growth

• Returns on invested capital significantly in excess of
Company’s cost of capital

• Annual increases in dividends

• Significant financial flexibility for opportunities in distressed
periods

• Conservative financial statements

• Committed to generating stock market value which is greater
than earnings retained

• We believe this will generate top quartile returns for our
shareholders

Oxy — Investment Attributes

Oxy’s Shareholder Equity versus Equity Market Value

1 - Year

3 - Year

5 - Year

10 - Year

Change in Equity
Market Value

($ in millions)

Creating Shareholder Value

Market Value per $ of Equity Retained

Change in
Shareholder Equity

Financial Data for period ended December 31, 2010.

$13,685

$3,325

$16,162

$9,626

$47,614

$17,042

$70,762

$27,710

4.1

1.7

2.8

2.6

A History of Generating Shareholder Value

Portions of this presentation contain forward-looking statements and involve risks and uncertainties that could materially affect
expected results of operations, liquidity, cash flows and business prospects. Factors that could cause results to differ
materially include, but are not limited to: global commodity pricing fluctuations; supply and demand considerations for
Occidental’s products; political events; not successfully completing, or any material delay of, any development of new fields,
expansion projects, capital expenditures, efficiency-improvement projects, acquisitions or dispositions; potential failure to
achieve expected production from existing and future oil and gas development projects; exploration risks such as drilling
unsuccessful wells; any general economic recession or slowdown domestically or internationally; higher-than-expected costs;
potential liability for remedial actions under existing or future environmental regulations and litigation; potential liability resulting
from pending or future litigation; general domestic and international political conditions; potential disruption or interruption of
Occidental’s production or manufacturing or damage to facilities due to accidents, chemical releases, labor unrest, weather,
natural disasters or insurgent activity; failure of risk management; changes in law or regulations; or changes in tax rates.
Finding and Development costs calculations inherently compare costs and reserves from separate periods. The United States
Securities and Exchange Commission (SEC) permits oil and natural gas companies, in their SEC filings, to disclose only
reserves anticipated to be economically producible, as of a given date, by application of development projects to known
accumulations. We use certain terms in this presentation, such as resource potential, net risked reserves, de-risked,
geologically viable, EUR (expected ultimate recovery), discovery volumes, likely recoverable resources and oil in place, that the
SEC’s guidelines strictly prohibit us from using in our SEC filings. These terms represent our internal estimates of volumes of
oil and gas that are not proved reserves but are potentially recoverable through exploratory driling or additional drilling or
recovery techniques and are not intended to correspond to probable or possible reserves as defined by SEC regulations. By
their nature these estimates are more speculative than proved, probable or possible reserves and subject to greater risk they will
not be realized. You should not place undue reliance on these forward-looking statements, which speak only as of the date of
this presentation. Unless legally required, Occidental does not undertake any obligation to update any forward-looking
statements, as a result of new information, future events or otherwise. U.S. investors are urged to consider carefully the
disclosures in our 2010 Form 10-K, available through the following toll-free number 1-888-OXYPETE (1-888-699-7383) or on
the internet at http://www.oxy.com. You also can obtain a copy form the SEC by calling 1-800-SEC-0330. We post or provide
links to important information on our website including investor and analyst presentations, certain board committee charters
and information that SEC requires companies and certain of its officers and directors to file or furnish. Such information may
be found in the “Investor Relations” and “Social Responsibility” portions of the website.

Cautionary Statement

Occidental Petroleum Corporation

Occidental Petroleum Corporation
Reconciliation to Generally Accepted Accounting Principles (GAAP)
For the Twelve Months Ended December 31,
($ Millions)

	2010					2009
				Diluted					Diluted
				EPS					EPS
Reported Income	$	4,530		$	5.56	$	2,915		$	3.58
Add: significant items affecting earnings
Asset impairments		275					-
Rig contract terminations		-					8
Railcar leases		-					15
Severance accrual		-					40
Tax effect of pre-tax adjustments		(100	)				(22	)
Benefit from foreign tax credit carry-forwards		(80	)				-
Discontinued operations, net *		39					236
Core Results	$	4,664		$	5.72	$	3,192		$	3.92

* Amount shown after-tax

Average Diluted Common Shares Outstanding					813.8					813.8

Occidental Petroleum Corporation
Reconciliation to Generally Accepted Accounting Principles (GAAP)
Return on Capital Employed (% )
($ Millions)

	2009		2010
GAAP measure - earnings applicable to common shareholders	2,915		4,530
Interest expense	109		93
Tax effect of interest expense	(38	)	(33	)
Earnings before tax-effected interest expense	2,986		4,590

GAAP stockholders' equity	29,159		32,484

DEBT
GAAP debt
Debt, including current maturities	2,796		5,111
Non-GAAP debt
Capital lease obligation	25		-
Total debt	2,821		5,111

Total capital employed	31,980		37,595

Return on Capital Employed (%)	9.6		13.2

Occidental Petroleum Corporation
Free Cash Flow
Reconciliation to Generally Accepted Accounting Principles (GAAP)
($ Millions)
	Twelve Months
	2010
Consolidated Statement of Cash Flows
Cash flow from operating activities	9,349
Cash flow from investing activities	(9,078	)
Cash flow from financing activities	1,083
Change in cash	1,354


Free Cash Flow
Cash flow from operating activities	9,349
Less:operating cash flow from discontinued operations	(210	)
Operating cash flow from continuing operations	9,139
Capital spending	(3,940	)
Cash dividends paid	(1,159	)
Equity method investment dividends	217
Free cash flow from continuing operations	4,257

Occidental Petroleum Corporation
Reconciliation to Generally Accepted Accounting Principles (GAAP)
Costs Incurred - Using Industry Convention of 6:1
F&D Costs

																									Averages
Annual Report Basis	2001		2002		2003		2004		2005			2006		2007			2008			2009		2010			3-Year			5-Year			10-Year
Property Acquisition Costs
Proved Properties		25		163		357		146		1,768			4,888		926			1,830			727		2,278			1,612			2,130			1,311
Unproved Properties		56		29		4		8		398			1,142		119			1,710			103		2,290			1,368			1,073			586
Acquisitions		81		192		361		154		2,166			6,030		1,045			3,540			830		4,568			2,979			3,203			1,897
Exploration Costs		171		134		97		158		255			316		327			334			207		329			290			303			233
Development Costs		918		897		1,080		1,435		1,844			2,426		2,740			4,112			2,779		3,387			3,426			3,089			2,162
		1,089		1,031		1,177		1,593		2,099			2,742		3,067			4,446			2,986		3,716			3,716			3,391			2,395

Costs Incurred		1,170		1,223		1,538		1,747		4,265			8,772		4,112			7,986			3,816		8,284			6,695			6,594			4,291


Reserve replacements
Improved recovery		143		142		102		120		139			140		254			247			173		259			226			214			172
Purchases of proved reserves		4		68		107		36		139			327		60			210			160		144			171			180			125
Others
Revisions of previous estimates		21		3		12		49		(12	)		12		(95	)		(145	)		58		(1	)		(29	)		(34	)		(10	)
Extensions & discoveries		76		50		147		64		124			34		23			24			92		7			41			36			64
Total Others		97		53		159		113		112			46		(72	)		(122	)		149		6			11			1			54
		244		263		368		269		390			512		241			335			483		409			409			396			351

Production		173		188		200		207		207			219		208			220			235		273			243			231			213

F&D Costs	$	4.80	$	4.65	$	4.18	$	6.51	$	10.93		$	17.14	$	17.04		$	23.84		$	7.90	$	20.25		$	16.38		$	16.66		$	12.22

Occidental Petroleum Corporation
Reconciliation to Generally Accepted Accounting Principles (GAAP)
Costs Incurred - Using Average Commodity Prices
F&D Costs

																								Averages
Annual Report Basis	2001		2002		2003		2004		2005			2006		2007			2008			2009		2010		3-Year			5-Year			10-Year
Property Acquisition Costs
Proved Properties		25		163		357		146		1,768			4,888		926			1,830			727		2,278		1,612			2,130			1,311
Unproved Properties		56		29		4		8		398			1,142		119			1,710			103		2,290		1,368			1,073			586
Acquisitions		81		192		361		154		2,166			6,030		1,045			3,540			830		4,568		2,979			3,203			1,897
Exploration Costs		171		134		97		158		255			316		327			334			207		329		290			303			233
Development Costs		918		897		1,080		1,435		1,844			2,426		2,740			4,112			2,779		3,387		3,426			3,089			2,162
		1,089		1,031		1,177		1,593		2,099			2,742		3,067			4,446			2,986		3,716		3,716			3,391			2,395

Costs Incurred		1,170		1,223		1,538		1,747		4,265			8,772		4,112			7,986			3,816		8,284		6,695			6,594			4,291


Reserve replacements
Improved recovery		143		135		102		115		136			133		225			220			156		204		194			188			157
Purchases of proved reserves		4		65		107		36		136			305		59			146			81		124		117			143			106
Others
Revisions of previous estimates		20		6		12		43		(13	)		13		(89	)		(131	)		104		10		(6	)		(19	)		(2	)
Extensions & discoveries		78		47		148		59		114			31		20			18			56		4		26			26			58
Total Others		98		53		161		102		101			44		(68	)		(113	)		159		15		20			7			55
		245		252		370		254		373			482		215			254			396		343		331			338			318

Production		177		177		200		201		201			206		190			197			202		225		208			204			198

F&D Costs	$	4.77	$	4.84	$	4.15	$	6.88	$	11.44		$	18.20	$	19.09		$	31.49		$	9.64	$	24.18	$	20.25		$	19.52		$	13.48

WTI	$	25.97	$	26.08	$	31.03	$	41.40	$	56.56		$	66.23	$	72.32		$	99.65		$	61.80	$	79.53	$	80.33		$	75.91		$	56.06

F&D Costs as a % of WTI		18%		19%		13%		17%		20%			27%		26%			32%			16%		30%		25%			26%			24%

Occidental Petroleum Corporation
Oil & Gas
Return on Assets
Reconciliation to Generally Accepted Accounting Principles (GAAP)
($ Millions)
						5-Year
	2006	2007	2008	2009	2010	Average

Revenues	10,949	12,583	17,378	10,984	14,245	13,228
Production costs	1,668	2,011	2,428	2,214	2,622	2,189
Other operating expense	469	516	536	628	655	561
Depreciation, depletion and amortization	1,487	1,754	1,993	2,258	2,668	2,032
Taxes other than income	381	401	569	413	472	447
Charges for impairments	-	58	81	-	275	83
Exploration expenses	289	361	308	254	262	295
Pretax income	6,655	7,482	11,463	5,217	7,291	7,622
Income tax expense	2,705	3,121	4,426	1,972	2,845	3,014
Results of operations	3,950	4,361	7,037	3,245	4,446	4,608
Depreciation, depletion and amortization	1,487	1,754	1,993	2,258	2,668	2,032
Charges for impairments	-	58	81	-	275	83
Gross Cash	5,437	6,173	9,111	5,503	7,389	6,723

Capitalized costs
Current year	17,375	19,137	24,216	25,228	29,901	23,171
Prior year	13,472	17,375	19,137	24,216	25,228	19,886
Average capitalized costs	15,424	18,256	21,677	24,722	27,565	21,529


5-Year Average	U.S.	International	Total
Results of operations	2,598	2,010	4,608	(a)
Depreciation, depletion and amortization	1,131	901	2,032
Charges for impairments	67	16	83
Gross Cash	3,795	2,928	6,723	(b)

Average capitalized costs	15,861	5,668	21,529	(c)

Net income return on assets (a) / (c)	16%	35%	21%

Cash flow return on assets (b) / (c)	24%	53%	31%