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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) November 15, 2011
OCCIDENTAL PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
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1-9210
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95-4035997
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(State or other jurisdiction
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(Commission
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(I.R.S. Employer
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of incorporation)
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File Number)
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Identification No.)
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10889 Wilshire Boulevard
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Los Angeles, California
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90024
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(Address of principal executive offices)
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(ZIP code)
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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 Executive Officer, in connection with the November 15, 2011, Bank of America Merrill Lynch 2011 Global 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
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(d)
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Exhibits
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99.1
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Presentation dated November 15, 2011.
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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.
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OCCIDENTAL PETROLEUM CORPORATION
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(Registrant)
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DATE: November 15, 2011
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/s/ DONALD P. DE BRIER
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Donald P. de Brier, Executive Vice President,
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General Counsel and Secretary
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EXHIBIT INDEX
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99.1
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Presentation dated November 15, 2011.
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EXHIBIT 99.1
Occidental Petroleum Corporation
Bank of America Merrill Lynch
2011 Global Energy Conference
Bank of America Merrill Lynch
2011 Global Energy Conference
Stephen I. Chazen
President and Chief Executive Officer
President and Chief Executive Officer
November 15, 2011
November 15, 2011
1
2
First Nine Months 2011 Results - Summary
First Nine Months 2011 Results - Summary
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9 Mos 2011
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9 Mos 2010
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• Core Results
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$5,187
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$3,377
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• Core EPS (diluted)
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$6.37
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$4.14
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• Net Income
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$5,137
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$3,318
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• Reported EPS (diluted)
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$6.31
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$4.07
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• Oil and Gas production volumes
(mboe/d) +3.6% |
728
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703
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• Capital Spending
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$4,969
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$2,580
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• Cash Flow from Operations
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$8,638
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$6,744
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• ROE - Annualized
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19.9%
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14.4%
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• ROCE - Annualized
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17.7%
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13.4%
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($ in millions, except EPS data)
See attached for GAAP reconciliation
2
3
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;
average over the long term;
• Allocating and deploying capital with a focus on achieving
well above cost-of-capital returns (ROE and ROCE);
well above cost-of-capital returns (ROE and ROCE);
– Return Targets*
• Domestic - 15+%
• International - 20+%
• Consistent dividend growth, that is superior to that of our
peers.
peers.
*Assumes Moderate Product Prices
What Is Our Philosophy & Strategy?
What Is Our Philosophy & Strategy?
3
4
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
5 Year Average
Return on Assets
See attached for GAAP reconciliation
(2006 - 2010)
4
5
F&D Costs
Actual as a % of
6:1 * Prices ** WTI Price
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
** 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)
(2008 - 2010)
5-Year Average $16.66 $19.52 26%
(2006 - 2010)
(2006 - 2010)
10-Year Average $12.22 $13.48 24%
(2001 - 2010)
(2001 - 2010)
See attached for GAAP reconciliation
5
6
• Our ability to pay dividends is indicated by our free cash
flow generation.
flow generation.
• Free cash flow after interest, taxes and capital spending,
but before dividends, acquisitions and debt activity for
the first nine months of 2011 was $3.7 billion.
but before dividends, acquisitions and debt activity for
the first nine months of 2011 was $3.7 billion.
• Oxy’s annual dividend rate is currently $1.84 per share or
about $1.1 billion for the nine months of 2011.
about $1.1 billion for the nine months of 2011.
• Oxy has increased its dividends 10 times over the last
9 years, resulting in a compound annual dividend growth
rate of 15.6%.
9 years, resulting in a compound annual dividend growth
rate of 15.6%.
• In keeping with our philosophy to raise the dividend on a
consistent basis, the Board of Directors is expected to
consider a dividend increase at the February meeting.
consistent basis, the Board of Directors is expected to
consider a dividend increase at the February meeting.
Dividend Growth
See attached for GAAP reconciliation
6
7
Dividend Growth
Annual dividend increased 21% to $1.84 per share, effective with the 4/15/11 payment
7
8
Worldwide Oil & Gas Producing Areas
Colombia
Colombia
Libya
Libya
Oman
Oman
UAE
UAE
Yemen
Yemen
Bolivia
Bolivia
Qatar
Qatar
Iraq
Iraq
Bahrain
Bahrain
Focus Areas
United States
United States
Permian
Permian
Basin
Basin
California
California
8
9
Geographic Value of Oxy’s Oil & Gas Reserves
(Percentage of Oxy total company value)
Note: excludes Argentina as the sale of this asset closed in February 2011; * as a percentage of total US value.
9
10
• About 60% of Oxy’s oil production tracks world oil prices
and 40% is indexed to WTI. For example:
and 40% is indexed to WTI. For example:
– In California our realized price was 114% of WTI and 91% of Brent
in 3Q11.
in 3Q11.
– In Oman our average price was 117% of WTI and 93% of Brent.
• Differentials improved in 3Q11, resulting in realized oil
prices representing 108% of the average WTI and 87% of
the average Brent price.
prices representing 108% of the average WTI and 87% of
the average Brent price.
Realized Prices & Differentials
Realized Prices & Differentials
10
11
• We expect capital spending for the total year 2011 to be
about $7.0 billion, compared to the total 2010 capital of
$3.9 billion.
about $7.0 billion, compared to the total 2010 capital of
$3.9 billion.
• Year to-date capital expenditures by segment were 83%
in Oil and Gas, 14% in Midstream and the remainder in
Chemicals.
in Oil and Gas, 14% in Midstream and the remainder in
Chemicals.
• Oxy's share of the Shah Field development capital will be
about $3 billion from 2012 through 2014, in addition to
spending of approximately $1 billion during 2011.
about $3 billion from 2012 through 2014, in addition to
spending of approximately $1 billion during 2011.
Capital Spending - 2011 Outlook
11
12
(excluding Argentina)
Capital Spending - 2011E vs. 2010 Actual
• Last year we provided a 2010 - 14 capital budget of $27.5 billion,
with average spending of $5.5 billion per year
with average spending of $5.5 billion per year
• Excluding capital for Shah project, estimated capital for 2010 - 11 of
$10.4 billion is in the range of that guidance
$10.4 billion is in the range of that guidance
Exploration
6%
6%
(assumes $75 oil)
12
13
• The impact of our capital program and increase in drilling
activity has started to have a visible impact on our domestic oil
and gas production volumes.
activity has started to have a visible impact on our domestic oil
and gas production volumes.
• Compared to 2Q11, our domestic production increased by
about 6 mboe/d per month, compared to our guidance of
3 to 4 mboe/d.
about 6 mboe/d per month, compared to our guidance of
3 to 4 mboe/d.
– This increase resulted in domestic production of 436 mboe/d for 3Q11,
representing ~3% sequential quarterly growth.
representing ~3% sequential quarterly growth.
– 3Q11 domestic production is the highest US total production volume in
Oxy’s history, reflecting the highest ever volumes for liquids.
Oxy’s history, reflecting the highest ever volumes for liquids.
• On a year-over-year basis, our domestic production volumes
have increased by 15%.
have increased by 15%.
• We believe our capital program will yield higher production
growth and reliability over time.
growth and reliability over time.
Domestic Oil & Gas Production - 3Q11
Domestic Oil & Gas Production - 3Q11
13
US Oil & Gas Capital and Production
$310
$704
$884
$640
389
403
443
424
436
$403
14
15
Oxy’s US Operated Rig Activity
15
16
• We expect 4Q11 oil and gas production to be as follows:
– Domestic volumes are expected to increase by about 3 to 4 mboe/d
per month from the 3Q11 average level of 436 mboe/d.
per month from the 3Q11 average level of 436 mboe/d.
– This should result in average 4Q11 production of about
442 to 444 mboe/d.
442 to 444 mboe/d.
– This would constitute a year-over-year domestic production
growth rate exceeding 10% and about a 6% per year production
growth rate going forward.
growth rate exceeding 10% and about a 6% per year production
growth rate going forward.
– We expect our 4Q11 international production to be about the same
as 3Q11 production, 4% higher than 2Q11, which was the low point
of volumes during the year following the situation in Libya.
as 3Q11 production, 4% higher than 2Q11, which was the low point
of volumes during the year following the situation in Libya.
– At 3Q11-end prices, we expect total production to increase to
around 745 mboe/d as a result of the 3 to 4 mboe/d per month
coming from domestic production.
around 745 mboe/d as a result of the 3 to 4 mboe/d per month
coming from domestic production.
– We expect sales volumes to be around 740 mboe/d due to the
timing of liftings.
timing of liftings.
Oil & Gas Production - 4Q11 Outlook
Oil & Gas Production - 4Q11 Outlook
16
17
• Base 5 - 8% Compounded Average Annual Growth
– CO2 in Permian
– Current California risked prospects
– Recent domestic properties acquisitions (Williston Basin,
South TX gas)
South TX gas)
– Oman
– Iraq
• Upside from Existing Holdings
– New California conventional and unconventional prospects
– Permian exploration
– Rockies
• Additional opportunities from balance sheet and cash
generation
generation
– Domestic properties acquisitions
– New Middle East projects
Oil & Gas Volume Growth Drivers
17
18
California Overview
California Overview
Los Angeles
Los Angeles
Bakersfield
Bakersfield
Oxy Acreage
• Largest acreage holder in CA
with ~1.6 mm acres, majority of
which are net mineral interests.
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.
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.
Field — the largest producer of
gas and NGLs in CA.
• Currently operating 30 drilling
rigs in the state.
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.
gas processing plant in 2010;
plan to start building a second
plant in the next two years.
18
19
California - 2011 Program Summary
THUMS
(Long Beach)
Los Angeles
Elk Hills
Buena Vista
Oxy Properties
Ventura Basin
San Joaquin Basin
• 2011 Capital program ~$1.6
billion, up ~80% vs. 2010.
billion, up ~80% vs. 2010.
• Plan to drill 500+ new
development wells.
development wells.
• Shifted our drilling to oil wells
which we expect to result in
higher oil production in 2011.
which we expect to result in
higher oil production in 2011.
• Drill ~20 exploration wells in
2011, several of which will be
for conventional opportunities.
2011, several of which will be
for conventional opportunities.
• We expect that the exploration
activity will, at a minimum,
create more unconventional
drilling locations.
activity will, at a minimum,
create more unconventional
drilling locations.
19
20
California Conventional Exploration
• World Class Province
– 35+ Billion BOE discovered
– 5 of top 12 U.S. oil fields
• Significant Remaining Potential
– Large undiscovered resources
– Multiple play and trap types
• Underexplored
• Oxy
– Major producer
– Largest acreage holder
– Successful explorer
– Multi-year prospect inventory
Sources:
California Division of Oil, Gas & Geothermal Resources
Gibson Consulting
Oxy Fee/Lease
2 Billion BOE
20 Billion BOE
3 Billion BOE
10 Billion BOE
Major Producing
Basins
Sacramento
Sacramento
San
Francisco
Francisco
San
Francisco
Francisco
Los Angeles
Los Angeles
Bakersfield
Bakersfield
20
21
Field Size (MMBOE)
<0.1
0.1
1
10
100
1 Billion
10 Billion
Discovery Play
Oxy Play Type and Prospect Exposure
Sources:
California Division of Oil, Gas & Geothermal Resources
Occidental Estimates
California Division of Oil, Gas & Geothermal Resources
Occidental Estimates
California Field Sizes
21
22
• Multi-year inventory of drill sites in
CA, many of which are both outside
of Elk Hills proper & the Kern County
Discovery Area
CA, many of which are both outside
of Elk Hills proper & the Kern County
Discovery Area
• Expect to drill 154 shale wells outside
Elk Hills proper, and 195 total shale
wells including Elk Hills in 2011
Elk Hills proper, and 195 total shale
wells including Elk Hills in 2011
• 30-day initial production rate for
these wells is between 300 and 400
BOE per day
these wells is between 300 and 400
BOE per day
• For the shale wells outside Elk Hills,
~80% of the BOE production is a
combination of black oil and high-
value condensate
~80% of the BOE production is a
combination of black oil and high-
value condensate
• Cost of drilling and completing the
wells has run ~$3.5 million per well,
which we expect to decline over time
wells has run ~$3.5 million per well,
which we expect to decline over time
California Unconventional “Shale” Program
22
23
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Play
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Depth
(ft)
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Thickness
(ft)
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Porosity
(%)
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Permeability
(mD)
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TOC
(%)
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CA “Shales”
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3,500’ -
16,000’ |
500’ - 3,500’
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5 - 30%
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<0.0001 - 2
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0.1 - 12%
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Bakken
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7,000’ -
11,000’ |
20’ - 100’
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3 - 12%
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0.05 - 0.5
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2 - 18%
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Eagle Ford
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8,000’ -
14,000’
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75’ - 300’
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3 - 15%
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<0.0001 - .003
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0.6 - 7%
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California “Shale” Summary and Play
Comparison
Comparison
• ~870,000 acres are within most prospective “shale” plays;
• We have “de-risked” approx. 200,000 acres as viable for “shale”;
• Oxy’s average NRI ~95%;
• Identified 15 areas to appraise (5 - 10% of total acreage);
– Average IP ~ 300 - 400 boepd;
– 10-acre spacing
• In 10 years CA “shale” could become Oxy’s largest business unit.
23
24
• We expect to drill and complete a total of 42 shale wells during
4Q11.
4Q11.
• We expect to run a 30 rig program in the state during 4Q11.
• Our conventional drilling program is progressing somewhat better
than planned.
than planned.
• With respect to the recent personnel turnover at the DOGGR, our
hope is that the permitting process becomes more transparent,
which would make planning our activity levels more predictable.
hope is that the permitting process becomes more transparent,
which would make planning our activity levels more predictable.
• Improved transparency and a clearing of the substantial backlog of
permits should allow for a gradual increase in our activity levels and
employment in the state.
permits should allow for a gradual increase in our activity levels and
employment in the state.
California Update
California Update
24
25
Permian Basin Overview
• Approximately 1.2 billion BOE of
proved reserves at year end 2010
proved reserves at year end 2010
• 2010 production of 197,000 boe/d
• Largest oil producer in Permian
(~16% share of total)
(~16% share of total)
• Largest operator in Permian
(of 1,500+ operators)
(of 1,500+ operators)
• ~66% of Oxy’s Permian oil
production is from CO2 related
EOR projects
production is from CO2 related
EOR projects
• Have another 2.5 BBOE of likely
recoverable resource
recoverable resource
• 1.7 bcf/d (0.5 tcf/year) of CO2
• Ample supply of CO2 accelerates
project implementations
project implementations
25
26
Permian - 2011 Program Summary
• 2011 Capital program ~$1 billion
• Plan to drill 300+ wells this year
• Expect to run ~24 rig drilling
program by year-end 2011
program by year-end 2011
• Drilling program is front-end
loaded to exploit quick
production first
loaded to exploit quick
production first
• 160+ workover/maintenance rigs
operating, and 50% more than a
year ago
operating, and 50% more than a
year ago
• Extensive Wolfberry drilling
program, as well as
Delaware/Bone Springs sands
and Avalon Shale
program, as well as
Delaware/Bone Springs sands
and Avalon Shale
26
27
• 4.1 BBO have been
produced,
produced,
• leaving 7.8 BBO net
remaining
remaining
4.6 BBO
3P Reserves
EOR Likely
EOR Potential
0.8 BBO
1.4 BBO
1.0 BBO
Residual
7.8 BBO Net Remaining
Permian EOR Opportunities
27
28
• In the Permian operations:
– Our CO2 flood production is progressing according to plan.
– We expect our rig count to be about 24 in 4Q11.
– Our non-CO2 operations have stepped up their development
program but will not show significant production growth until
next year.
program but will not show significant production growth until
next year.
• In Williston:
– We are pursuing a development program with about 13 rigs
expected to be running in 4Q11.
expected to be running in 4Q11.
– Our production is growing as a result of the development
program and we expect the growth to continue.
program and we expect the growth to continue.
• Natural gas prices in the US continue to be weak. As a result,
we are considering cutting back our pure gas drilling in the
Midcontinent and possibly elsewhere.
we are considering cutting back our pure gas drilling in the
Midcontinent and possibly elsewhere.
Permian, Midcontinent & Other Update
Permian, Midcontinent & Other Update
28
29
• Acquired ~174,000 contiguous net acres within the southern
extents of the ND Bakken and Three Forks Formations.
extents of the ND 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.
Middle Bakken and Upper Three Forks Formations.
• Prospective across entire acreage position for Three Forks
and deeper objectives.
and deeper objectives.
• We expect to exit the year with production of about
8 - 10 mboe/d.
8 - 10 mboe/d.
• Oxy expects to grow production in the Williston Basin to at
least 30 mboe/d over the next five years.
least 30 mboe/d over the next five years.
– Currently running 12 drilling rigs on our Bakken acreage with plans to
increase this to 13 rigs by the end of 2011
increase this to 13 rigs by the end of 2011
– Plan to drill ~60 Bakken shale wells during 2011
Oxy - North Dakota Assets
29
30
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
MT
ND
Dawson
Golden
Valley
Other Notable Areas of
Williston Basin Production
Williston Basin Production
Other Oxy Operated
Acreage
Acreage
Oxy Acquisition Area
Burleigh
Sheridan
McHenry
Bottineau
Bismarck
SD
Oxy North Dakota - Williston Basin
30
31
Oxy - Qatar Oil & Gas Fields
• Idd El Shargi North Dome
(ISND) - 4 B bo ROIP
(ISND) - 4 B bo ROIP
• Idd El Shargi South Dome
(ISSD) - 800 MM bo ROIP
(ISSD) - 800 MM bo ROIP
• Al Rayyan - 300 MM bo ROIP
• 2010 Gross Production 118
Mbopd, Net 76 Mbopd
Mbopd, Net 76 Mbopd
• Priorities:
– Maintain production from
existing fields
existing fields
– Additional activity to
increase production later
in the 2012 - 2014 period
increase production later
in the 2012 - 2014 period
Qatar
Qatar
Al Rayyan
Gas Project
Idd El Shargi
North Dome (ISND)
North Dome (ISND)
Idd El Shargi
South Dome (ISSD)
Saudi Arabia
Saudi Arabia
Bahrain
Doha
Umm Sa’id
31
32
Oxy - Qatar Gross Oil Production
32
33
• Oxy share 24.5%
• Delivering 2.2 Bcfd to UAE
and 200 MMcfd to Oman
markets
and 200 MMcfd to Oman
markets
• 2010 Gross production 537
mboepd, Net production 63
mboepd
mboepd, Net production 63
mboepd
• Consistently above anticipated
gas / liquids production
gas / liquids production
• Fee income for UAE distribution
and 3rd party sales increasing
and 3rd party sales increasing
• Exceptional financial returns
Dubai
Taweelah
Jebel Ali
Abu Dhabi
Al Ain
Fujayrah
Umm Sa’id
Doha
Al Hawailah
Dolphin
ISND
ISSD
Block 12
Al Rayyan
Qatar
Saudi Arabia
United Arab Emirates
Oman
Iran
48” Export Pipeline
Jarn
Yaphour
Oxy - Dolphin Project
33
34
Oxy Oman History
• Oxy commenced operation of the
Safah field in 1984
Safah field in 1984
• Approximately 600 wells drilled
and 30+ fields discovered in
Blocks 9 and 27
and 30+ fields discovered in
Blocks 9 and 27
• Signed 30-year PSC for the
Mukhaizna field in 2005
Mukhaizna field in 2005
• Block 62 acquired in 2008, and
pursuing exploration and
development opportunities
pursuing exploration and
development opportunities
• 2010 Gross production 190
mboepd, Net production 69
mboepd
mboepd, Net production 69
mboepd
34
35
Oxy Oman Gross Production Growth
35
36
• World Class Steam flood project
• 2 B bo ROIP
• Discovered in 1975 in South
Central Oman
Central Oman
• Cold production commenced 1992
• Oxy assumed operation
September 1, 2005 at 8,500 b/d
September 1, 2005 at 8,500 b/d
• Steam flood commenced May
2007, and had drilled 1,020+ new
wells through 2010
2007, and had drilled 1,020+ new
wells through 2010
• Current Gross Production:
~120,000 b/d
~120,000 b/d
• Target Gross Production:
150,000 b/d
150,000 b/d
Oxy Oman - Mukhaizna Project
36
37
Abu Dhabi - Al Hosn Gas Project (Shah Field)
37
• Shah Gas Field one of the largest
in the Middle East
in the Middle East
• Oxy holds a 40% participating
interest under a 30-year contract
interest under a 30-year contract
• The project involves development
of high-sulfur content reservoirs
within the Shah field, located
onshore ~180 km so. west of AD
of high-sulfur content reservoirs
within the Shah field, located
onshore ~180 km so. west of AD
• Production start-up is scheduled
in late 2014
in late 2014
• Anticipated to produce ~500 mmcf
per day of sales gas - providing
net to Oxy in the range of 200
mmcf per day, plus condensate
and NGLs of at least 20 mb/d
per day of sales gas - providing
net to Oxy in the range of 200
mmcf per day, plus condensate
and NGLs of at least 20 mb/d
• Capex is estimated to be ~$10
billion for the project with Oxy’s
share proportional to its interest
billion for the project with Oxy’s
share proportional to its interest
37
38
1. Base/Maintenance Capital
2. Dividends
3. Growth Capital
4. Acquisitions
5. Share Repurchase
Cash Flow Priorities
38
39
See attached GAAP reconciliation.
– Free cash flow from continuing operations after capex and dividends,
but before acquisition and debt activity, was about $2.6 billion.
but before acquisition and debt activity, was about $2.6 billion.
Summary - YTD 2011 Cash Flow
15
39
40
• Company’s core business is acquiring assets that can
provide future growth through improved recovery.
provide future growth through improved recovery.
– Foreign contracts
– Domestic add-ons
– Small incremental additions to production in short term
• Generate returns of at least 15% in the US and 20% overseas.
• Overall average finding & development costs of less than
25% of selling price.
25% of selling price.
• Even with the additional capital shown, program will
generate a significant amount of free cash flow.
generate a significant amount of free cash flow.
• Acquisitions are measured against reinvesting in the existing
business with the goal of enhancing company value.
business with the goal of enhancing company value.
• Large number of opportunities over 5-year period.
Acquisition Strategy
40
41
• 5 - 8% base annual production growth
• Opportunity for additional volume growth
• Returns on invested capital significantly in excess of
Company’s cost of capital
Company’s cost of capital
• Annual increases in dividends
• Significant financial flexibility for opportunities in distressed
periods
periods
• Conservative financial statements
• Committed to generating stock market value which is greater
than earnings retained
than earnings retained
• We believe this will generate top quartile returns for our
shareholders
shareholders
Oxy - Investment Attributes
41
42
Oxy’s Shareholder Equity versus Equity Market Value
1 - Year
3 - Year
5 - Year
10 - Year
Change in Equity
Market Value
Market Value
($ in millions)
A History of Generating Shareholder Value
Creating Shareholder Value
Market Value per $ of Equity Retained
Change in
Shareholder Equity
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
42
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; general domestic political and regulatory approval conditions; 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 drilling 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.
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; general domestic political and regulatory approval conditions; 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 drilling 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
43
Occidental Petroleum Corporation
44
|
Occidental Petroleum Corporation
|
|||||||||||||
|
Reconciliation to Generally Accepted Accounting Principles (GAAP)
|
|||||||||||||
|
For the Nine Months Ended September 30,
|
|||||||||||||
|
(Stated in millions, except per share amounts)
|
|||||||||||||
|
2011
|
2010
|
||||||||||||
|
Diluted
|
Diluted
|
||||||||||||
|
EPS
|
EPS
|
||||||||||||
|
Reported Income
|
$
|
5,137
|
$
|
6.31
|
$
|
3,318
|
$
|
4.07
|
|||||
|
Add: significant items affecting earnings
|
|||||||||||||
|
Exploration write-off of Libyan properties
|
35
|
-
|
|||||||||||
|
Gain from the sale of an interest in Colombia pipeline
|
(22
|
)
|
-
|
||||||||||
|
Foreign special tax
|
29
|
-
|
|||||||||||
|
Premium on debt extinguishments
|
163
|
-
|
|||||||||||
|
State income tax charge
|
33
|
-
|
|||||||||||
|
Tax effect of adjustments
|
(50
|
)
|
-
|
||||||||||
|
Discontinued operations, net *
|
(138
|
)
|
59
|
||||||||||
|
Core Results
|
$
|
5,187
|
$
|
6.37
|
$
|
3,377
|
$
|
4.14
|
|||||
|
* Amount shown after-tax
|
|||||||||||||
|
Average Diluted Common Shares Outstanding
|
813.3
|
813.8
|
|||||||||||
|
Occidental Petroleum Corporation
|
|||||||
|
Return on Capital Employed (ROCE)
|
|||||||
|
Reconciliation to Generally Accepted Accounting Principles (GAAP)
|
|||||||
|
9 Months
|
Annualized
|
||||||
|
2010
|
2011
|
2011
|
|||||
|
GAAP measure - net income attributable
|
4,530
|
5,137
|
|||||
|
to common stock
|
|||||||
|
Interest expense
|
93
|
259
|
|||||
|
Tax effect of interest expense
|
(33
|
)
|
(91
|
)
|
|||
|
Earnings before tax-effected interest expense
|
4,590
|
5,305
|
|||||
|
GAAP stockholders' equity
|
32,484
|
36,479
|
|||||
|
Debt
|
5,111
|
5,870
|
|||||
|
Total capital employed
|
37,595
|
42,349
|
|||||
|
ROCE
|
13.2
|
13.3
|
17.7
|
||||
|
Occidental Petroleum Corporation
|
||
|
Free Cash Flow
|
||
|
Reconciliation to Generally Accepted Accounting Principles (GAAP)
|
||
|
($ Millions)
|
||
|
Nine Months
|
||
|
2011
|
||
|
Consolidated Statement of Cash Flows
|
||
|
Cash flow from operating activities
|
8,638
|
|
|
Cash flow from investing activities
|
(6,488
|
)
|
|
Cash flow from financing activities
|
(689
|
)
|
|
Change in cash
|
1,461
|
|
|
Free Cash Flow
|
||
|
Cash flow from operating activities
|
8,638
|
|
|
Capital spending
|
(4,969
|
)
|
|
Dividends
|
(1,060
|
)
|
|
Free cash flow after dividends
|
2,609
|
|
|
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
|
||||||||||||||
|
This schedule reflects the disclosure made in each year's respective annual report -- it has not been restated for DISCO.
|
||||||||||||||||||||||||||||||||||||||||
|
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%
|
||||||||||
|
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
|
|||||||||
|
Chemicals
|
|||||||||
|
EBITDA as a Percentage of Sales
|
|||||||||
|
Reconciliation to Generally Accepted Accounting Principles (GAAP)
|
|||||||||
|
($ Millions)
|
|||||||||
|
3-Year
|
|||||||||
|
2008
|
2009
|
2010
|
Average
|
||||||
|
Net Sales
|
5,112
|
3,225
|
4,016
|
4,118
|
|||||
|
Segment income
|
669
|
389
|
438
|
499
|
|||||
|
Add: significant items affecting earnings
|
|||||||||
|
Plant closure and impairments
|
90
|
-
|
-
|
30
|
|||||
|
Core results - EBIT
|
759
|
389
|
438
|
529
|
|||||
|
DD&A Expense
|
311
|
298
|
321
|
310
|
|||||
|
EBITDA
|
1,070
|
687
|
759
|
839
|
|||||
|
EBITDA as a % of Sales
|
20.9%
|
21.3%
|
18.9%
|
20.4%
|
|||||