OCCIDENTAL PETROLEUM CORP /DE/ - FORM 8-K - EX-99.2 - EXHIBIT 99.2

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EXHIBIT 99.2

Occidental Petroleum Corporation

JAMES M. LIENERT

Executive Vice President and Chief Financial Officer

– Conference Call –

Third Quarter 2011 Earnings Announcement

October 27, 2011

Los Angeles, California

Thank you Chris.

Core income was $1.8 billion or $2.18 per diluted share in the third quarter this year, compared to $1.2 billion or $1.48 per diluted share in the third quarter of last year. Net income was $1.8 billion or $2.17 per diluted share in the third quarter of 2011, compared to $1.2 billion or $1.46 per diluted share in the third quarter of 2010. The small difference between net and core income is due to discontinued operations.

Here’s the segment breakdown for the third quarter.

Oil and gas segment earnings for the third quarter of 2011 were $2.6 billion, the same as the second quarter of 2011 and compared to $1.8 billion in the third quarter of 2010. Higher volumes this quarter, compared to the second quarter of 2011, resulted in flat quarter to quarter income despite lower product prices. The improvement in 2011, over the same period in 2010, was driven by higher production and liquids prices. The third quarter 2011 realized prices increased on a year-over-year basis by 34 percent for

crude oil, 41 percent for NGLs and remained about flat for domestic natural gas. Sales volumes, which are different than production volumes due to the timing of liftings, were 743,000 BOE per day, compared to 713,000 BOE per day in the third quarter of 2010. Our production was 739,000 BOE per day, compared to 706,000 in the third quarter of 2010, which included production from Libya. This represents a greater than 4 ½ percent increase year-over-year, reflecting our continued focus on production growth. The third quarter production was also more than 3 percent higher than the second quarter 2011 volumes of 715,000 BOE per day.

●	Domestically, our production was 436,000 BOE per day, representing the highest ever domestic production volumes for the company, compared to our guidance of 430,000 to 432,000 BOE per day. Our production in California rose by 6,000 BOE per day compared to the second quarter, and contributed a large portion of the sequential increase in our overall domestic production volumes.
●	Latin America volumes were 30,000 BOE per day. Colombia volumes decreased from the second quarter due to pipeline interruptions caused by insurgent activity.
●	In the Middle East region:
		○	We recorded no production in Libya.
		○	In Iraq, we produced 4,000 BOE per day.
		○	Yemen daily production was 28,000 BOE, slightly ahead of our guidance.

		○	In Oman, the third quarter production was 79,000 BOE per day, an increase of 3,000 BOE per day over the second quarter volumes.
		○	In Qatar, the third quarter production was 73,000 BOE per day, an increase of 5,000 BOE per day over the second quarter volumes. The increase reflected the results of the development program, as well as maintenance issues that affected the second quarter volumes.
		○	In Dolphin and Bahrain combined, production increased 3,000 BOE per day from the second quarter volumes.
●	Our third quarter sales volumes were 743,000 BOE per day, compared to our guidance of 725,000 BOE per day. The improvement resulted mainly from the higher domestic production and the timing of liftings.
●	Third quarter 2011 realized prices declined for all our products from the second quarter of the year. Our worldwide crude oil realized price was $97.24 per barrel, a decrease of 6 percent, worldwide NGLs were $56.06 per barrel, a decline of 3 percent, and domestic natural gas prices were about flat at $4.23 per MCF.
●	Differentials improved in the quarter, resulting in realized oil prices representing 108 percent of the average WTI and 87 percent of the average Brent price. About 60 percent of Oxy’s oil production tracks world oil prices and 40 percent is indexed to WTI. For example, in California our realized price was 114 percent of WTI and 91 percent of Brent in the third quarter. In Oman our average price was 117 percent of WTI and 93 percent of Brent.

	●	Price changes at current global prices, affect our quarterly earnings before income taxes by $38 million for a $1.00 per barrel change in oil prices and $7 million for a $1.00 per barrel change in NGL prices. A swing of 50 cents per million BTUs in domestic gas prices affects quarterly pre-tax earnings by about $34 million.
	●	Oil and gas cash production costs were $12.36 a barrel for the first nine months of 2011, compared with last year's twelve-month costs of $10.19 a barrel. The cost increase reflects higher workover and maintenance activity driven by our program to increase production at these higher levels of oil prices.
	●	Taxes other than on income, which are directly related to product prices, were $2.29 per barrel for the first nine months of 2011, compared to $1.83 per barrel for all of 2010.
	●	Total exploration expense was $39 million in the quarter.

Chemical segment earnings for the third quarter of 2011 were $245 million, compared to $253 million in the second quarter of 2011 and $189 million in the third quarter of 2010. The improvement in third quarter results on a year-over-year basis reflects higher margins across most product lines. In addition, during the third quarter of 2011, we temporarily idled certain production in our Texas plants and sold power to the grid during the power shortage, resulting in an increase in the quarter’s earnings.

Midstream segment earnings for the third quarter of 2011 were $77 million, compared to $187 million in the second quarter of 2011 and $163 million in the third quarter of 2010. The decreases from the second quarter and prior year third quarter earnings were due to losses from our Phibro unit both for the quarter and year-to-date, partially offset by higher pipeline income and increased power sales to the grid during the third quarter.

The worldwide effective tax rate was 38 percent for the third quarter of 2011. Our third quarter U.S. and foreign tax rates are included in the “Investor Relations Supplemental Schedule.”

Let me now turn to Occidental’s performance during the first nine months.

Core income was $5.2 billion or $6.37 per diluted share, compared with $3.4 billion or $4.14 per diluted share in 2010. Net income was $5.1 billion or $6.31 per diluted share for the first nine months of 2011, compared with $3.3 billion or $4.07 per diluted share in 2010.

Cash flow from operations for the first nine months of 2011 was $8.6 billion. We used $5.0 billion of the company’s total cash flow to fund capital expenditures and $1.5 billion on net acquisitions and divestitures. We used $1.1 billion to pay dividends and had a net cash inflow from debt activity of $0.6 billion. These and other net cash flows resulted in a $4.0 billion cash balance at September 30.

Capital spending was $5.0 billion for the first nine months, of which $2.0 billion was spent in the third quarter. Year-to-date capital expenditures by segment were 83 percent in oil and gas, 14 percent in midstream and the remainder in chemicals.

Our net acquisition expenditures in the first nine months were $1.5 billion, which are net of proceeds from the sale of our Argentina operations. The acquisitions included the South Texas purchase, properties in California and the Permian, and a payment in connection with the signing of the Al Hosn Gas project in Abu Dhabi which is the gas development of the Shah field. This payment was for Occidental’s share of development expenditures incurred by the project prior to the date the final agreement was signed.

The weighted-average basic shares outstanding for the first nine months of 2011 were 812.6 million and the weighted-average diluted shares outstanding were 813.3 million.

Our debt-to-capitalization ratio was 14 percent, the same as at the end of last year. During the third quarter of 2011, Oxy issued senior notes of $1.3 billion due in 2017 and $900 million due in 2022 at a weighted average interest rate of 2.3 percent, which brought the Company’s average effective borrowing rate down to 3.2 percent.

Our annualized return on equity for the first nine months of the year was 20 percent.

Copies of the press release announcing our third quarter earnings and the Investor Relations Supplemental Schedules are available on our website at www.oxy.com or through the SEC’s EDGAR system.

I will now turn the call over to Steve Chazen to discuss Oxy’s strategy to maximize total shareholder return and provide guidance for the fourth quarter.

Occidental Petroleum Corporation

STEPHEN CHAZEN

President and Chief Executive Officer

– Conference Call –

Third Quarter 2011 Earnings Guidance

October 27, 2011

Los Angeles, California

Thank you Jim.

This morning, I want to spend a few minutes discussing Occidental’s overriding goal to maximize Total Shareholder Return. We believe this can be achieved through a combination of:

	1.	Growing our oil and gas production by 5% to 8% per year on average over the long term;
	2.	Allocating and deploying capital with a focus on achieving well above cost-of-capital returns; and
	3.	Consistent dividend growth.

Following is an update of our progress to-date:

● Oil and gas production – 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. Compared to the second quarter, our domestic production increased by about 6,000 BOE per day per month, compared to

		our guidance of 3,000 to 4,000 BOE per day. This increase resulted in domestic production of 436,000 BOE/D for the third quarter, compared to the 430,000 to 432,000 BOE/D guidance we gave you. The third quarter 2011 domestic production is the highest U.S. total production volume in Occidental’s history, reflecting the highest ever volumes for liquids.
		● Compared to the prior year, total company third quarter production of 739,000 BOE per day was affected by a 7-percent decline in our international production. This reduction was the result of disruptions in the Middle East/North Africa region, and the impact of higher oil prices on our production sharing contracts. On a year-over-year basis, our domestic production volumes increased by 15 percent.
		In our operations we experience disruptions affecting our production. Examples of such events in the third quarter 2011 included the Elk Hills gas plant shutdown due to mechanical issues, mechanical issues with plants, compressors and pipelines in the Permian and Qatar, and insurgent activity in Colombia that caused a significant portion of our production to be shut down for about 10 days. Without these events our production would have been 10,000 to 15,000 BOE per day higher, which is more representative of our assets’ current theoretical productive capacity. Some of these constraints have been removed and we expect others to be removed over time. Others are not within our control and reoccur. We believe our

	capital program will yield higher production growth and reliability over time.
●	Returns –
		○	ROE – Oxy’s annualized return on equity for the first nine months of 2011 was 20 percent.
		○	ROCE – Occidental’s annualized return on capital employed for the first nine months of 2011 was 18 percent.
		○	We continue to manage our capital program and acquisition strategy to yield well above cost-of-capital returns.
●	Dividend growth – Our ability to pay dividends is indicated by our free cash flow generation. Free cash flow after interest, taxes and capital spending, but before dividends, acquisitions and debt activity for the first nine months of the year 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. Oxy has increased its dividends 10 times over the last 9 years, resulting in a compound annual dividend growth rate of 15.6 percent. 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.
●	Share repurchases –
		○	The policy on possible share repurchases remains essentially unchanged. We do not view share repurchases as an alternative to dividends. We believe that dividends are given directly to the shareholders

			○	Normally, this results in a decision to invest in the business rather than a decision to buy in shares. When we do repurchase shares we will make only the required public announcements, in order to minimize what we pay for the stock – thereby enriching the remaining shareholders and not assisting the exiting shareholders. This approach eliminates our natural bias to think that the stock is always undervalued and makes the calculation pretty straightforward.
			○	We have sufficient current authority to purchase a significant number of shares. The Form 10Q filings will show if any shares were purchased, at what price and how many shares remain authorized. Small repurchases are indicative of employee plan activities.
			○	We value the Company’s financial flexibility, especially in times of stress. It would be a disservice to our shareholders to impair that flexibility to achieve some theoretical short-term advantage.

As we look ahead to the fourth quarter of the year:

We expect the fourth quarter oil and gas production to be as follows:

●

Domestic volumes are expected to increase by about 3,000 – 4,000 BOE per day per month from the current quarterly average level of 436,000 BOE per day. This should result in average fourth quarter production of about 442,000 to 444,000 BOE per day.

This would constitute a year-over-year domestic production growth rate exceeding 10 percent and about a 6 percent per year production growth rate going forward.
In terms of a review of our major domestic assets:
	○	In California:
			§	For the year, we expect to drill and complete 154 shale wells outside Elk Hills, compared to the 107 wells we had indicated at the beginning of the year. Including Elk Hills, we expect to drill 195 shale wells for the year. We expect to drill and complete a total of 42 shale wells during the fourth quarter.
			§	Our experience has been that the 30-day initial production rate for these wells is between 300 and 400 BOE per day.
			§	With respect to the shale wells outside Elk Hills, about 80 percent of the BOE production is a combination of black oil and high-value condensate;
			§	The cost of drilling and completing the wells has been running about $3.5 million per well, and we expect this to decline over time;
			§	Our conventional drilling program is progressing somewhat better than planned;
			§	There has been no significant change in the status of permitting issues in the state from our last call. We expect the current permitting levels to allow

					our program to go forward at these levels and enable us to continue to grow our production volumes in the state.
				§	We expect the rig count to remain the same at 29.
		○	In the Permian operations:
				§	Our CO2 flood production is progressing according to plan;
				§	We expect our rig count to be about 24 in the fourth quarter;
				§	Our non-CO2 operations have stepped up their development program but they 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 the fourth quarter;
				§	Our production is growing as a result of the development program and we expect the growth to continue.
		○	Natural gas prices in the U.S. continue to be weak. As a result, we are considering cutting back our pure gas drilling in the Midcontinent and possibly elsewhere.
●	Internationally, we believe that once the current uncertainties are behind us, including the resolution of the situation in Libya and the achievement of a sustained development program in Iraq, we will achieve production growth similar to our domestic operations. We expect our fourth quarter international

		production to be about the same as the third quarter production, 4 percent higher than the second quarter of this year, which represented the low point of volumes during the year following the situation in Libya.
			○	Colombia volumes should be modestly higher than the third quarter, assuming no further pipeline attacks.
			○	The Middle East region production is expected to be as follows for the fourth quarter:
					§	At this point, we expect no significant production from Libya. Our joint venture partnerships are currently in the process of resuming production, but production ramp-up will be hampered in the near term by lack of vehicles and personnel to address operational problems from the prolonged shut-in.
					§	In Iraq, we expect production to be similar to the past quarter. Going forward, we still are unable to reliably predict spending levels, which determine production.
					§	In the remainder of the Middle East, we expect production to be comparable to third quarter volumes.
●	At quarter-end prices, we expect total production to increase to around 745,000 BOE per day as a result of the 3,000 to 4,000 BOE per day per month coming from domestic production. We expect sales volumes to be around 740,000 BOE per day due to the timing of liftings.

	●	A $5.00 change in global oil prices would impact our production sharing contracts daily volumes by about 3,000 BOE per day.
	●	We expect our total year capital expenditures to be about $7.0 billion.

Additionally –

	●	We expect exploration expense to be about $100 million for seismic and drilling for our exploration programs in the fourth quarter.
	●	The chemical segment fourth quarter earnings, which are historically the weakest quarter, are expected to be about $100 million. This reduction from the third quarter is due to seasonal slowdowns in many markets such as construction, customers’ efforts to minimize inventories and a slowdown in exports.
	●	We expect our combined worldwide tax rate in the fourth quarter of 2011 to remain at about 38 percent.

So to summarize:

	●	Our third quarter core income of $2.18 per share was about 12 percent higher than the analysts’ consensus estimate;
	●	Our third quarter oil and gas earnings of $2.6 billion were essentially unchanged from the second quarter, despite a $6 per barrel decline in our average oil realizations;
	●	Our annualized return on equity was 20 percent for the first nine months of 2011;
	●	Our total oil and gas production of 739,000 BOE per day during the third quarter grew more than 3 percent compared to the second quarter;

	●	Domestic oil and gas production volumes grew to 436,000 BOE per day in the third quarter a 3-percent increase from the second quarter, and above our earlier guidance of 430,000 to 432,000 BOE per day;
	●	Domestic volumes are expected to further increase by about 3,000 – 4,000 BOE per day per month in the fourth quarter.

Now we're ready to take your questions.

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	)
Free cash flow from continuing operations before dividends	3,669

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

			9 Months		Annualized
	2010		2011		2011
RETURN ON EQUITY (%)	14.7		14.9		19.9

RETURN ON CAPITAL EMPLOYED (%)	13.2		13.3		17.7


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

ROE	14.7		14.9		19.9

while the effect of share repurchases on the stock price is at best murky. Therefore, you should not expect a program of regular share repurchases except to offset any shares issued under employee programs. These numbers tend to be very small. If there’s continuing excess cash, it will be used to boost the dividend rate. We do consider using the shareholders’ capital to buy shares when the stock is trading at a discount to the results we can expect from our capital or acquisition program.

To assist you in determining this, the analysis we employ is as follows:

The value of the chemical and midstream assets that are not related directly to our production is determined. This is done on a conservative basis. The debt and cash levels of the Company are netted.

The current capital program finding and development costs for each of oil and gas are estimated. We use only proved reserves in the calculation, not probable and possible reserves, and we don’t consider the value of acreage.

The result of this analysis is not the value of the Company but rather a determination of whether the next dollar should be spent on capital or share repurchases.