Attached files
| file | filename |
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| 8-K - FORM 8-K - OCCIDENTAL PETROLEUM CORP /DE/ | form8k-20130131.htm |
| EX-99.4 - EXHIBIT 99.4 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_4-20130131.htm |
| EX-99.1 - EXHIBIT 99.1 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_1-20130131.htm |
| EX-99.3 - EXHIBIT 99.3 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_3-20130131.htm |
| EX-99.5 - EXHIBIT 99.5 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_5-20130131.htm |
EXHIBIT 99.2
Occidental Petroleum Corporation
CYNTHIA L. WALKER
Executive Vice President and Chief Financial Officer
– Conference Call –
Fourth Quarter 2012 Earnings Announcement
January 31, 2013
Los Angeles, California
Thank you Chris.
Core income was $1.5 billion or $1.83 per diluted share in the fourth quarter of 2012, compared to $1.6 billion or $2.02 per diluted share in the fourth quarter of 2011 and $1.4 billion or $1.70 per diluted share in the third quarter of 2012. The improvement from the third quarter reflected the effect of higher liquids production, higher realized NGL and domestic gas prices and reduced operating expenses in the oil and gas business, partially offset by lower earnings in the midstream segment.
In the fourth quarter we recorded pre-tax charges of $1.8 billion, representing $1.1 billion after-tax or $1.41 per diluted share. Almost all of the charges were for impairments in the Oil and Gas Midcontinent business units, over 90 percent of which was related to natural gas properties, which were acquired more than four years ago on average. While the performance of the properties was generally as expected, natural gas prices have declined by approximately 50% since the acquisitions. Natural gas and NGL prices
used for reserve calculations in 2012 were significantly lower than prices used in 2011, resulting in declines in economically feasible reserves in these properties. In addition, despite the recent modest increase in gas prices, drilling in many gassy areas remains uneconomical. As a result, we continue to operate at minimal levels in these areas as we have discussed previously. The charges related to the natural gas properties reflect the impairment of such properties to approximate fair value.
Net income after the fourth quarter charge I mentioned was $336 million, or $0.42 per diluted share.
I will now discuss the segment breakdown of results for the fourth quarter.
Oil and gas earnings for the fourth quarter of 2012, excluding the charge I mentioned, were $2.3 billion, compared to $2.0 billion in the third quarter of 2012 and $2.5 billion in the fourth quarter of 2011. We delivered a quarter-over-quarter improvement, despite the decline in WTI prices, as a result of higher liquids production, higher realized NGL and domestic gas prices and, importantly, lower operating expenses.
Oil and gas production costs were $14.99 per barrel for the twelve months of 2012, compared with $12.84 per barrel for the full year 2011. Our fourth quarter production costs were $14.95 per barrel, which was $1.04 per barrel lower than the third quarter level. I would note that these reductions occurred during the course of the quarter and our year-end exit rate on a per barrel basis was lower than the fourth quarter 2011 average and well below the fourth quarter 2012 level, giving us confidence as we begin 2013. Steve will review the drivers of the improvement and our expectations for 2013 in more detail.
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The fourth quarter 2012 total daily production on a BOE basis was 779,000 barrels, a new record set by the company, and was up 13,000 barrels per day from the third quarter of 2012, and up 4 percent from the fourth quarter of 2011. Approximately 6,000 barrels, or almost half of the total sequential increase in quarterly production, came from domestic operations, mainly in California and Permian, almost all of which was attributable to higher oil production.
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Our domestic production was 475,000 barrels per day, an increase of 6,000 barrels per day from the third quarter of 2012 and now the ninth consecutive quarterly domestic volume record for the company. Production was 6 percent higher than the fourth quarter of 2011. All of the net sequential quarterly increase came from oil production in California and Permian. Domestic gas production was down slightly from the third quarter, which was offset by higher liquids production resulting from higher yields from our new Elk Hills gas plant.
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Latin America volumes were 32,000 barrels per day, which was flat compared to the prior quarter and the same period in 2011.
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In the Middle East, production was 272,000 barrels per day, an increase of 7,000 barrels from the third quarter of 2012 volumes. Higher spending levels in Iraq and Oman resulted in 8,000 barrels per day higher production. Dolphin production was lower due to the full cost recovery of pre-startup capital. Other factors affecting production sharing and similar contracts, including oil prices, did not significantly impact this quarter’s production volumes compared to the fourth quarter of 2011 or the third quarter of 2012. Details regarding other country-specific production levels are
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available in the Investor Relations Supplemental Schedules we provide.
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Fourth quarter realized prices were mixed for our products compared to the third quarter of the year. Our worldwide crude oil realized price was $96.19 per barrel, a slight decrease from the third quarter; while worldwide NGLs were $45.08 per barrel, an increase of about 11 percent, and domestic natural gas prices were $3.09 per MCF, an improvement of 25 percent.
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Fourth quarter 2012 realized prices were lower than the prior year fourth quarter prices for all our products. On a year-over-year basis, price decreases were 3 percent for worldwide crude oil, 18 percent for worldwide NGLs and 14 percent for domestic natural gas.
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Realized oil prices for the quarter represented 109 percent of the average WTI price and 87 percent of the average Brent price. Realized NGL prices were 51 percent of the average WTI price and realized domestic gas prices were 92 percent of the average NYMEX price.
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At current global prices, a $1.00 per barrel change in oil prices affects our quarterly earnings before income taxes by $37 million and $7 million for a $1.00 per barrel change in NGL prices. A change in domestic gas prices of 50 cents per million BTUs affects quarterly pre-tax earnings by about $30 million. These price change sensitivities include the impact of production-sharing and similar contract volume changes.
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Taxes other than on income, which are generally related to product prices, were $2.39 per barrel for the full year of 2012, compared with $2.21 per barrel for the full year of 2011.
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Fourth quarter exploration expense was $82 million. We expect first quarter 2013 exploration expense to be about $90 million for seismic and drilling in our exploration programs.
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Our fourth quarter DD&A rate was $14.47 per barrel and we expect the full year 2013 rate to be approximately $17 per barrel.
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Chemical segment earnings for the fourth quarter of 2012 were $180 million, compared to $162 million in the third quarter of 2012 and $144 million for the fourth quarter of 2011. The sequential quarterly improvement reflected higher caustic soda and PVC prices, partially offset by higher energy and feedstock costs. The year-over-year increase reflected higher export volumes for caustic soda and VCM and lower feedstock costs. The chemical segment first quarter 2013 earnings are expected to be about $150 million. Typical weak seasonal demand, particularly in the construction and agricultural market segments, combined with the recent increases in ethylene and natural gas costs may, however, tighten margins in the first quarter.
Midstream segment earnings were $75 million for the fourth quarter of 2012, compared to $156 million in the third quarter of 2012 and $70 million in the fourth quarter of 2011. The 2012 sequential quarterly decrease in earnings was caused by lower marketing and trading, foreign pipeline and power generation earnings.
The worldwide effective tax rate on core income was 37 percent for the fourth quarter of 2012. The rate was lower than the prior quarter and our guidance, largely due to higher proportion of domestic income in the fourth
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quarter than foreign income. Our fourth quarter U.S. and foreign tax rates are included in the Investor Relations Supplemental Schedules. We expect our combined worldwide tax rate in the first quarter of 2013 to increase to about 40 percent.
In the twelve months of 2012, we generated $12.1 billion of cash flow from continuing operations before changes in working capital. Working capital changes reduced our full year cash flow from operations by approximately $800 million to $11.3 billion. Capital expenditures for the twelve months of 2012 were $10.2 billion, of which $2.5 billion was spent in the fourth quarter. The fourth quarter 2012 capital spend was approximately $100 million lower than the third quarter 2012, driven by an approximately 12 percent reduction in oil and gas spending, partially offset by increases in the chemical and midstream segments. The higher capital at chemicals was related to the construction of a new membrane chlor-alkali plant in Tennessee, which is expected to be completed by the fourth quarter of 2013. Midstream capital was higher mainly due to the Al Hosn gas project. Total year capital expenditures by segment were 80 percent in oil and gas, 15 percent in midstream and the remainder in chemicals. Acquisitions for the twelve months of 2012 were $2.5 billion, of which $1.3 billion was spent in the fourth quarter on domestic oil and gas properties. Financial activities, which included five quarterly dividends paid, stock buybacks and a $1.74 billion borrowing earlier this year, resulted in a net use of cash of $850 million. These and other net cash flows resulted in a $1.6 billion cash balance at December 31.
During the year, we bought about 7.5 million of our own shares at a cost of about $580 million. Approximately 5 million of the shares were purchased in the fourth quarter at an average price of $76.15.
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The weighted-average basic shares outstanding for the twelve months of 2012 were 809.3 million and the weighted-average diluted shares outstanding were 810.0 million. The weighted-average basic shares outstanding for the fourth quarter of 2012 were 807.1 million and the weighted-average diluted shares outstanding were 807.7 million. We had approximately 805.5 million shares outstanding at the end of the year.
Our debt-to-capitalization ratio was 16 percent at year-end.
Our return on equity in 2012 using core results was 14.6 percent and the return on capital employed was 12.6 percent.
Copies of the press release announcing our fourth quarter earnings and the Investor Relations Supplemental Schedules are available on our website at oxy.com or through the SEC’s EDGAR system.
I will now turn the call over to Steve Chazen to discuss our 2013 capital program, year-end oil and gas reserves and provide guidance for the first half of the year.
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Throughout this presentation, barrels may refer to barrels of oil, barrels of liquids or barrels of oil equivalents or BOE, which include natural gas, as the context requires.
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Occidental Petroleum Corporation
STEPHEN CHAZEN
President and Chief Executive Officer
– Conference Call –
Fourth Quarter 2012 Earnings Guidance
January 31, 2013
Los Angeles, California
Thank you Cynthia.
Occidental’s domestic oil and gas segment produced record volumes for the ninth consecutive quarter and continued to execute on our oil production growth strategy. The fourth quarter domestic production of 475,000 barrel equivalents per day, consisting of 342,000 barrels of liquids and 800 million cubic feet per day of gas, was an increase of 6,000 barrel equivalents per day compared to the third quarter of 2012. The increase in the domestic production over the third quarter 2012 was almost entirely in oil, which grew from 260,000 barrels per day to 265,000. Gas production declined 12 million cubic feet per day on a sequential quarterly basis, mainly in the Midcontinent, which reflects the reduction in gas-directed drilling we have mentioned over the past couple of quarters. Higher natural gas liquids volumes, resulting from better yields from our new Elk Hills gas plant, offset the decline in the gas production. Our total year domestic production grew from 428,000 barrels per day in 2011 to 465,000 per day in 2012, or
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about 9 percent. Our total year domestic oil production grew by 11 percent from 230,000 barrels per day in 2011 to 255,000 barrels in 2012.
The company's total daily production reached a record 779,000 barrels per day in the fourth quarter and 766,000 barrels for the full year. This resulted in a 5 percent increase for the total year.
We have embarked on an aggressive plan to improve our operational efficiencies over all cost categories, including capital – with a view toward achieving an appreciable reduction in our operating expenses and drilling costs to at least 2011 levels in order to create higher margins from our production.
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With regard to driving efficiencies in our cash operating costs, we are running well ahead of plan. We recognize that cost efficiency is the result of many decisions that are made at all levels of the organization, in particular numerous decisions that are made at the field level. All of our business units stepped up to the challenge of reducing our costs and involved their personnel at all levels, from business unit management all the way to field level personnel, to generate ideas to improve cost efficiency and our employees responded. The business units generated many good ideas, large numbers of which were generated by field level personnel. Many of these ideas have already been implemented and the results are apparent through reductions already realized in operating expenses. There are still many more big and small ideas that are in the process of being implemented, which we believe will result in additional improvements. In the fourth quarter, the total company production costs were $1.04 per barrel lower than the third
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quarter amount. Improvements were realized across most business units, most notably in the Permian and Elk Hills. The reductions resulted from efficiencies achieved across most cost categories including savings in surface operations, reductions in the use of outside contractors, curtailment of uneconomic down-hole maintenance and workover activity as well as related overhead. In 2013, we expect to realize further improvements in all of these categories. We expect our production costs per barrel to be under $14.00 in 2013, which is significantly lower than the 2012 average costs. Many of the steps already taken during the fourth quarter of 2012, which is only partially reflected in the quarter's average costs, along with additional measures being implemented early in the year, should result in meaningful additional cost reductions in 2013 and beyond.
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We are seeing strong early results from our efforts toward improving drilling efficiency and cutting our well costs through the simplification of our well design, focusing our activities on fewer geologic play types and favoring higher return conventional activity. Our goal for 2013 is to reduce our U.S. drilling costs by 15 percent compared to 2012 and we are approximately halfway toward that target with further improvements expected during the next couple of quarters.
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We have increased our dividends at a compounded annual rate of 15.8 percent over the last 10 years through 11 dividend increases. We expect to announce a further dividend increase after the meeting of the Board of Directors in the second week of February. As a result of our consistent long-term record of growing our dividend, we are proud to have been selected for
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inclusion in Mergent’s Dividend Achievers indices for 2013. This is a highly regarded series of indices that track companies with strong long-term dividend growth.
2012 Oil and Gas Reserves
We haven't completed the determination of our year-end reserve levels, but based on our preliminary estimates:
We produced approximately 280 million barrels of oil equivalent in 2012. Our total company reserve replacement ratio from all categories, including revisions, was about 143 percent, or about 400 million barrels.
Depressed domestic gas prices and changes in our plans for drilling on gas properties resulted in negative revisions in domestic gas reserves. Natural gas reserve revisions represented about 60 percent of the total revisions. If gas prices recover in the future, a portion of these reserves will be reinstated. Additionally, we experienced some negative revisions due to reservoir performance.
Our 2012 development program, excluding acquisitions and revisions, replaced about 175 percent of our production with about 490 million barrels of reserve adds. Our 2012 program, including acquisitions but excluding revisions of prior year estimates, replaced 209 percent of our production. We believe these latter two approaches are an appropriate way of evaluating the progress of our overall program.
At year end, we estimate that 72 percent of our total proved reserves were liquids. Of the total reserves, about 73 percent were proved developed reserves.
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I will now turn to our 2013 outlook.
Production
Domestically, we expect oil production for all of 2013 to grow by about 8 percent to 10 percent from the 2012 average. With lower drilling on gas properties, we expect gas and NGL production to decline somewhat. Planned plant turnarounds in the Permian CO2 business will cause additional volatility to production in the first half of the year.
Internationally, at current prices we expect production to be lower in the first quarter due to a planned turnaround in Qatar. Production should be relatively flat the rest of the year compared to the fourth quarter of 2012.
Capital Program
We are currently in an investing phase in many of our businesses where a higher than normal portion of our capital is spent on longer-term projects. In 2013, we expect to spend about 25 percent of our total capital expenditures on projects that will make a significant contribution to our earnings and cash flow over the next several years. I have previously talked about the Al Hosn gas project. We have also started the construction of the BridgeTex pipeline, which we expect will start operations in 2014. This pipeline is designed to deliver crude oil from West Texas to the Houston area refineries, which will open up additional markets for our oil from the Permian region and improve our margins. We are also investing in gas and CO2 processing plants to expand the capacity of these facilities to handle future production growth and in a new chlor-alkali plant in the chemical business.
Our overall capital spending is expected to decline by approximately 6 percent in 2013 to $9.6 billion from the $10.2 billion we spent in 2012. The reduction in capital will come entirely from the oil and gas business where the fourth quarter spend rate was already close to the level planned for all of
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2013. Almost all of the reductions will be made in domestic operations. Midstream capital spending will increase mainly for the BridgeTex pipeline. The 2013 program breakdown is expected to be about 75 percent in Oil and Gas, 11 percent in the Al Hosn gas project, 9 percent in domestic Midstream and the remainder in Chemical.
Following is a geographic overview of the 2013 program:
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In domestic oil and gas, development capital will be about 46 percent of our total capital program.
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We expect our average operated rig count in the United States to be about 55 rigs during 2013 compared to 64 rigs in 2012, a decline of about 14 percent. We have eliminated our less productive rigs to improve our returns.
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Our total domestic oil and gas capital is expected to decrease about $900 million compared to 2012. Permian capital should remain flat. In California, we expect to reduce capital about $500 million from the 2012 level, which represents ongoing well cost reductions and efficiencies, a modest shift toward more conventional drilling opportunities and the constraints of the current environment. To improve the efficiency of our capital spending in California, we have planned our 2013 program level based on what we know we can execute with our existing and conservatively anticipated permits. We may revise our program during the course of the year if we can gain more certainty about the environment. In the Midcontinent, we expect to reduce spending about $400 million from our 2012 level. We have reduced our activity in higher cost unconventional oil plays, specifically in the Williston and in
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lower return gas properties, mainly in the Midcontinent and Rockies.
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The modest decline in rig levels, combined with well cost reductions will lead to a decline in overall U.S. oil and gas capital spending compared with 2012. However, as a result of planned efficiencies we expect to drill a similar number of wells as we did in 2012. Compared to the 2012 split, we will spend a higher percentage of our 2013 capital on oil projects, and as a result we expect our U.S. oil production to continue to grow this year.
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Internationally:
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Our total Al Hosn gas project capital will decline modestly from the 2012 levels, and will make up about 11 percent of our total capital program for the year.
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While Iraq’s spending levels continue to be difficult to predict reliably, capital in the rest of the Middle East region is expected to be comparable to the 2012 levels.
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Exploration capital should decrease about 15 percent from the 2012 spending levels and represent about 5 percent of the total capital program. The focus of the program domestically will be in the Permian basin and California, with additional international drilling in Oman.
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The U.S. Midstream capital will increase by about $400 million due to the BridgeTex pipeline project.
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Chemical segment capital will be about $425 million, which includes the construction of a new 182,500 ton per year membrane chlor-alkali plant in New Johnsonville, Tennessee that we expect will start operating in the fourth quarter.
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In summary, assuming similar realized oil and gas prices to 2012 and our expectation of comparable chemical and midstream segment earnings:
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We expect that our 2013 program will:
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generate cash flow from operations of about $12.7 billion; and
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invest about $9.6 billion in capital spending;
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In 2012, we returned $2.3 billion in total cash to shareholders, in the form of dividends and share repurchases, excluding the fourth quarter accelerated payout.
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Our dividends (excluding the fourth quarter accelerated payout) in 2012 were $1.7 billion. We expect this amount to increase in 2013, on an annualized basis, by an amount comparable to our recent dividend growth rate.
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We expect that a five dollar change in our realized oil prices will change cash flow from operations by about $450 million.
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Now we're ready to take your questions.
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Throughout this presentation, barrels may refer to barrels of oil, barrels of liquids or barrels of oil equivalents or BOE, which includes natural gas, as the context requires.
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Occidental Petroleum Corporation
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Return on Equity and Capital Employed on a Core Income Basis
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For the Twelve Months Ended December 31, 2012
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Reconciliation to Generally Accepted Accounting Principles (GAAP)
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Reported
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Core
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Income
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Income
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RETURN ON EQUITY (%)
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11.8%
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14.6%
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RETURN ON CAPITAL EMPLOYED (%)
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10.3%
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12.6%
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GAAP measure - net income
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4,598
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4,598
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Non-core adjustments:
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Asset impairments and related items
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-
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1,751
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Tax effect of pre-tax adjustments
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-
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(636)
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Discontinued operations, net
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-
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37
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Total non-core adjustments
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-
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1,152
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Core income
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4,598
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5,750
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Interest expense
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117
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117
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Tax effect of interest expense
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(41
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)
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(41
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)
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Earnings before tax-effected interest expense
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4,674
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5,826
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GAAP stockholders' equity
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40,048
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40,048
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Non-core adjustments
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-
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1,152
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CORE stockholders' equity
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40,048
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41,200
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Debt
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7,623
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7,623
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Total capital employed
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47,671
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48,823
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