Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - OCCIDENTAL PETROLEUM CORP /DE/ | form8k-20110428.htm |
| EX-99.1 - EXHIBIT 99.1 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_1-20110428.htm |
| EX-99.3 - EXHIBIT 99.3 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_3-20110428.htm |
| EX-99.4 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_4-20110428.htm |
| EX-99.5 - EXHIBIT 99.5 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_5-20110428.htm |
EXHIBIT 99.2
Occidental Petroleum Corporation
STEPHEN CHAZEN
President and Chief Operating Officer
– Conference Call –
First Quarter 2011 Earnings Announcement
April 28, 2011
Los Angeles, California
Thank you Chris.
Core income was $1.6 billion or $1.96 per diluted share in the first quarter this year, compared to $1.1 billion or $1.35 per diluted share in the first quarter of last year. Non-core items amounted to a net after-tax charge of $44 million. Non-core items included pre-tax gains of $225 million from the sale of the Argentina operations and $22 million from the sale of an interest in a Colombia pipeline. Non-core pre-tax charges included $163 million related to the early redemption of $1.4 billion face value of debt, $35 million write-off of the entire accumulated cost of exploration properties in Libya and non-recurring charges for state and foreign taxes of $62 million. This resulted in net income of $1.5 billion or $1.90 per diluted share in the first quarter of 2011, compared to $1.1 billion or $1.31 per diluted share in the first quarter of 2010.
We reorganized our Permian operations into two business units. One unit will hold the CO2 flood assets and the other will operate the
conventional production. In connection with these, we moved the production from Southwest Texas, which was previously part of Midcontinent and other, into the Permian. Midcontinent and other includes production from the recently acquired South Texas and North Dakota properties.
Natural Gas Liquids account for about 10 percent of our oil and gas volumes and sell at a discount to crude oil. Starting this quarter, we are reporting NGL and crude oil production and sales volumes separately as opposed to the previously disclosed combined liquids volumes. See the Investor Relations Supplemental Schedules for the 2010 quarterly realized prices and production and sales volumes reflecting these changes.
Here’s the segment breakdown for the first quarter.
Oil and gas segment and core earnings for the first quarter of 2011 were $2.5 billion, compared with $1.9 billion in the first quarter of 2010. Realized prices increased 24 percent for crude oil in 2011 and 11 percent for NGL prices on a year-over-year basis but domestic natural gas prices declined 25 percent from the first quarter of 2010. Sales volumes for the first quarter of 2011 were 728,000 BOE per day, a 6 percent increase compared with 685,000 BOE per day for the first quarter of 2010.
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The production guidance we gave you in last quarter’s conference call of 740,000 to 750,000 BOE per day was at an $85 average price assumption. The actual average first quarter oil price reduced our production volumes by about 10,000 BOE per day, including 1,000 BOE per day at THUMS in Long Beach. As we previously disclosed, our Iraq production was lower by about 9,000 BOE per day due to less than planned spending levels as we are in the start-up phase of operations. Inclement weather, mainly
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in Texas, caused an additional reduction of about 7,000 BOE per day.
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These reductions were offset by less than expected production loss from the Elk Hills maintenance shutdown and operational enhancements providing higher than expected production in Colombia, Yemen, Qatar and the new assets resulting in production of 730,000 BOE per day. See the production and sales volume reconciliation schedules in the Investor Relations Supplemental Schedules.
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First quarter production of 730,000 BOE per day was higher than the fourth quarter 2010 production of 714,000 BOE per day. First quarter volumes, compared to the prior year fourth quarter, included 25,000 BOE per day from new domestic acquisitions in South Texas and the North Dakota Williston Basin.
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Sales volumes of 728,000 BOE per day, which was higher than our guidance of 725,000 BOE per day, differ from production volumes due to the timing of liftings, principally caused by Iraq where liftings are expected in the latter half of 2011.
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First quarter 2011 realized prices improved for all our products over the fourth quarter 2010 prices. Worldwide crude oil realized price was $92.14 per barrel, an increase of 15 percent, worldwide NGLs were $52.64 per barrel, an improvement of 7 percent, and domestic natural gas prices were $4.21 per MCF, an increase of 2 percent.
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Oil and gas cash production costs were $11.30 a barrel for the first quarter of 2011, compared with last year's twelve-month costs of
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$10.19 a barrel. The increase reflects increased workovers and maintenance activity and higher costs for energy.
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Taxes – other than on income, which are directly related to product prices, were $2.25 per barrel for the first quarter of 2011, compared to $1.83 per barrel for all of 2010.
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Total exploration expense was $84 million in the quarter. This amount included the Libya write off of $35 million, which is included in non-core items discussed earlier.
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Chemical segment earnings for the first quarter of 2011 were $219 million, which were greater than our earlier guidance. These results are among the best ever reported for the Chemical segment’s first quarter operations, which is historically a weak quarter due to seasonal factors. First quarter operations were positively impacted by strong export demand and improved supply/demand balances across most products resulting in higher margins, including higher demand for calcium chloride resulting from the severe winter storms in the Northeast and Midwest sections of the United States.
Midstream segment earnings for the first quarter of 2010 were $114 million, compared to $202 million in the fourth quarter of 2010 and $94 million in the first quarter of 2010. The decrease from fourth quarter earnings was mainly due to lower marketing and trading income.
The worldwide effective tax rate on core income was 40 percent for the first quarter of 2011, which is in line with our guidance.
Capital spending for the first quarter of 2011 was $1.3 billion. Of this, about 88 percent was in oil and gas, 10 percent in midstream and the remainder in chemicals. We are currently operating 16 rigs in the Permian
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and 24 rigs in California, compared to 5 and 11 rigs, respectively, in the first quarter of 2010.
Cash flow from operations for the first three months of 2011 was $2.2 billion. In addition, we received $2.7 billion in proceeds from the sale of assets and used $1.3 billion of the company’s cash flow to fund capital expenditures and $3.0 billion on acquisitions. We used $310 million to pay dividends and $1.5 billion to retire debt. We borrowed $1.0 billion at quarter end for short-term needs, which has now been repaid. These and other net cash flows reduced our $2.6 billion cash balance at the end of last year by $500 million to $2.1 billion at March 31. Free cash flow from continuing operations after capital spending and dividends but before acquisition and debt activity was about $500 million.
Acquisitions
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Our acquisition expenditures in the first quarter were $3.0 billion. The acquisitions included the previously announced South Texas purchase and properties in California and the Permian. Excluding the South Texas purchase, the new properties did not materially impact the first quarter volumes.
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During the second quarter, we will make a payment of about $500 million in connection with the signing of the Shah Field Development Project. This amount represents development costs incurred by the project prior to the effective date of our participation. Future development costs will be reflected in capital expenditures.
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The weighted-average basic shares outstanding for the first three months of 2011 were 812.6 million and the weighted-average diluted shares outstanding were 813.4 million.
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Our debt to capitalization ratio declined to 12 percent, compared with 14 percent at the end of last year. Our remaining outstanding debt has an average interest rate of 3.7 percent.
As we look ahead in the current quarter:
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At first quarter average oil prices of about $95 WTI, we expect the second quarter oil and gas production volumes to be as follows:
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Domestic volumes are expected to increase to about 425,000 BOE per day, compared with the first quarter daily production of 404,000 BOE.
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Latin America is expected to be comparable to Quarter 1 volumes.
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In the Middle East region, an overwhelming majority of the value, using SEC’s standardized measure, and income comes from Qatar, including Dolphin, and Oman where operations are running normally;
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With regard to second quarter production from the Middle East region:
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We expect no production for Libya.
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Production levels in Iraq are not easily predictable due to volatile spending levels at this early stage of that project. This is caused by the nature of the contract, which allows immediate recovery of expenditures through cost recovery barrels. As a result, the level of development spending in any given period has an immediate impact on volumes for that period.
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In Yemen, almost all of our production comes from concessions operated by others. In addition, the Masila Field contract, which produces, net to us, about 11,000 BOE per day, is approaching expiration at the end of 2011 and capital spending is being phased out. These factors make the forecasting of production volumes very difficult.
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For the remainder of the Middle East, we expect production to be comparable to first quarter volumes.
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Total sales volumes are expected to be about 725,000 BOE per day, which do not include any volumes from Iraq or Libya.
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A $5.00 increase in WTI would reduce our production sharing contracts daily volumes by about 3,500 BOE per day.
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We are increasing our total year capital program to $6.8 billion, with about $500 million of the increase related to the Shah Field development program subsequent to the effective date of our participation and the remainder principally in California for spending attributable to additional permits being obtained.
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With regard to prices -
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At current market prices, a $1.00 per barrel change in oil prices impacts quarterly earnings before income taxes by about $34 million. The average first quarter WTI oil price was $94.10 per barrel.
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A $1.00 per barrel change in WTI prices impacts NGL quarterly earnings before income taxes by $4 million.
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A swing of 50-cents per million BTUs in domestic gas prices has a $34 million impact on quarterly earnings before income taxes. The current NYMEX gas price is around $4.25 per MCF.
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Additionally -
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We expect exploration expense to be about $85 million for seismic and drilling for our exploration programs.
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The chemical segment second quarter earnings are expected to be comparable to the first quarter. We expect continuation of the first quarter trends with sufficient gains from strong exports and seasonal demand improvement offsetting the reduced contributions from the calcium chloride business.
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We expect our combined worldwide tax rate in the second quarter of 2011 to be about 39 percent. Our first quarter U.S. and foreign tax rates are included in the “Investor Relations Supplemental Schedule.”
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In California
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We are continuing the program I discussed in last quarter’s conference call, which is progressing with satisfactory results. Permitting is still an issue but we have recently obtained some permits that make us optimistic about increasing our second half capital spending. Governor Brown has been working to speed up the permitting process. We expect that his effort will be successful, which should enable us to increase our activity and add more jobs in the state.
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In the first quarter, we drilled and completed 26 shale wells outside of the Elk Hills field.
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Copies of the press release announcing our first quarter earnings and the Investor Relations Supplemental Schedules are available on our website at www.oxy.com or through the SEC’s EDGAR system.
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Now we're ready to take your questions.
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Occidental Petroleum Corporation
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Free Cash Flow
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Reconciliation to Generally Accepted Accounting Principles (GAAP)
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($ Millions)
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Three Months
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2011
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Consolidated Statement of Cash Flows
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Cash flow from operating activities
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2,222
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Cash flow from investing activities
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(1,741
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)
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Cash flow from financing activities
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(959
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)
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Change in cash
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(478
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)
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Free Cash Flow
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Cash flow from operating activities
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2,222
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Capital spending
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(1,325
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)
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Cash dividends paid
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(310
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)
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Distribution to noncontrolling interest
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(121
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)
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Free cash flow from continuing operations
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466
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