Attached files
| file | filename |
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| EX-99.3 - EXHIBIT 99.3 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_3-20121025.htm |
| EX-99.1 - EXHIBIT 99.1 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_1-20121025.htm |
| EX-99.4 - EXHIBIT 99.4 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_4-20121025.htm |
| 8-K - FORM 8-K - OCCIDENTAL PETROLEUM CORP /DE/ | form8k-20121025.htm |
| EX-99.5 - EXHIBIT 99.5 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_5-20121025.htm |
EXHIBIT 99.2
Occidental Petroleum Corporation
CYNTHIA L. WALKER
Executive Vice President and Chief Financial Officer
– Conference Call –
Third Quarter 2012 Earnings Announcement
October 25, 2012
Los Angeles, California
Thank you Chris.
Income from continuing operations was $1.4 billion or $1.70 per diluted share in the third quarter of 2012, compared to $1.8 billion or $2.18 per diluted share in the third quarter of 2011 and $1.3 billion or $1.64 per diluted share in the second quarter of 2012.
The third quarter income from continuing operations improved $0.06 per diluted share from the second quarter of 2012. The improvement reflected higher margins in the marketing and trading businesses, partially offset by lower earnings in the chemical segment. In the oil and gas business, the effect of higher liquids production and domestic gas prices was partially offset by the impact of a 3 percent decline in realized worldwide crude oil prices.
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Here’s the segment breakdown for the third quarter.
Oil and gas segment earnings for the third quarter of 2012 were $2.0 billion, compared with $2.0 billion in the second quarter of 2012 and $2.6 billion in the third quarter of 2011.
The third quarter 2012 total daily production was 766,000 barrels, flat with the record set by the company in the second quarter of 2012, and up 4 percent from the third quarter of 2011.
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Our domestic production was 469,000 barrels per day, an increase of 7,000 barrels from the second quarter of 2012 and the eighth consecutive quarterly domestic volume record for the company. Production was 8 percent higher than the third quarter of 2011. Almost all of the sequential quarterly increase came from the Permian and Williston Basins. California production was higher in liquids but flat on a BOE basis with the second quarter, mainly due to lower gas volumes associated with the initial start-up issues of the new gas plant. These issues were resolved mid-quarter although the positive effect of the plant on overall third quarter production was limited. California's current production run rate is approximately 150,000 barrels per day.
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Latin America volumes were 32,000 barrels per day.
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In the Middle East region, volumes were 265,000 barrels per day. I will note meaningful sequential changes in Qatar production. Details regarding other country-specific production levels are available as usual in the Investor Relations Supplemental Schedules we provide. Dolphin's production was 13,000 barrels per day lower than the second quarter resulting from the full cost recovery of pre-startup capital, as we noted last quarter. Qatar's
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production was also impacted by a facility outage in August, which reduced production by 5,000 barrels per day. The outage was subsequently resolved. The rest of the Middle East partially offset these decreases in part due to higher spending levels. Factors affecting production sharing and similar contracts, including oil prices, did not significantly impact this quarter’s production volumes compared to the third quarter of 2011 or the second quarter of 2012.
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Third quarter 2012 realized prices were mixed for our products compared to the second quarter of the year. Our worldwide crude oil realized price was $96.62 per barrel, a decrease of about 3 percent; worldwide NGLs were $40.65 per barrel, also a decrease of about 3 percent from the second quarter; while domestic natural gas prices were $2.48 per MCF, an improvement of 19 percent. The change in worldwide crude oil realized price was primarily due to the mix of sales volumes in the third quarter.
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Third quarter 2012 realized prices were lower than third quarter 2011 prices for all our products. On a year-over-year basis, price decreases were one percent for worldwide crude oil, 27 percent for worldwide NGLs and 41 percent for domestic natural gas.
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Realized oil prices for the quarter represented 105 percent of the average WTI and 88 percent of the average Brent price. Realized NGL prices were 44 percent of the average WTI and realized domestic gas prices were 90 percent of the average NYMEX price.
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Price changes at current global prices affect our quarterly earnings before income taxes by $36 million for a $1.00 per barrel change in oil prices and $8 million for a $1.00 per barrel change in NGL
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prices. A swing of 50 cents per million BTUs in domestic gas prices affects quarterly pre-tax earnings by about $35 million. These price change sensitivities include the impact of production-sharing and similar contract volume changes on income.
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Oil and gas production costs were $15.00 per barrel for the first nine months of 2012, compared with $12.84 per barrel for the full year 2011. The cost increase reflects higher well maintenance activity, in part reflecting our higher well count, higher workover activity and higher support and injection costs.
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Taxes other than on income, which are generally related to product prices, were $2.43 per barrel for the first nine months of 2012, compared with $2.21 per barrel for the full year of 2011.
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Third quarter exploration expense was $69 million.
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Chemical segment earnings for the third quarter of 2012 were $162 million, compared to $194 million in the second quarter of 2012 and $245 million for the third quarter of 2011. Both the sequential quarterly and year-over-year declines were due to lower Asian market demand that drove export prices lower, partially offset by lower ethylene costs.
Midstream segment earnings were $156 million for the third quarter of 2012, compared to $77 million in the second quarter of 2012 and in the third quarter of 2011. The 2012 quarterly increase in earnings was in the marketing and trading businesses and power generation, partially offset by lower margins in the gas plants, reflecting lower NGL prices.
The worldwide effective tax rate was 38 percent for the third quarter of 2012. The lower rate compared to our guidance was attributable to a shift in the mix of income toward domestic. Our third quarter U.S. and foreign tax rates are included in the Investor Relations Supplemental Schedules.
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In the first nine months of 2012, we generated $9.2 billion of cash flow from operations before working capital changes. Working capital reduced our nine-month cash flow from operations by approximately $660 million to $8.5 billion. Approximately $510 million of the working capital use occurred in the third quarter. Capital expenditures for the first nine months of 2012 were $7.7 billion, of which $2.6 billion was spent in the third quarter. Year-to-date capital expenditures by segment were 82 percent in oil and gas, 14 percent in midstream and the remainder in chemicals. Acquisitions for the first nine months of 2012 were $1.2 billion, of which $100 million was spent in the third quarter. Financial activities, which included dividends paid, stock buybacks and a $1.74 billion borrowing earlier this year, provided a net $300 million of cash flow. These and other net cash flows resulted in a $3.8 billion cash balance at September 30.
The weighted-average basic shares outstanding for the first nine months of 2012 were 810.1 million and the weighted-average diluted shares outstanding were 810.8 million. Diluted shares outstanding at the end of the quarter were approximately 810.1 million.
Our debt-to-capitalization ratio was 16 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.
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I will now turn the call over to Steve Chazen to discuss an update on our operations and strategy and provide guidance for the fourth quarter 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 –
Third Quarter 2012 Earnings Guidance
October 25, 2012
Los Angeles, California
Thank you Cynthia.
Occidental’s domestic oil and gas segment produced record volumes for the eighth consecutive quarter and continued to execute on our liquids production growth strategy. The third quarter domestic production of 469,000 barrel equivalents per day, consisting of 334,000 barrels of liquids and 812 million cubic feet per day of gas, was an increase of 7,000 barrel equivalents per day compared to the second quarter of 2012. The increase in the domestic production over the second quarter 2012 was almost entirely in oil, which grew from 249,000 barrels a day to 260,000. Gas production declined 28 million cubic feet per day on a sequential quarterly basis, mainly in California, some of which was due to the initial start-up issues of the new gas plant that Cynthia mentioned. Compared to the third quarter of 2011, our domestic production grew by 8 percent, or 33,000 barrels a day, of which 30,000 was oil production growth.
Our annualized return on equity for the first nine months of 2012 was 15 percent and return on capital employed was 13 percent.
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Strategy and Operations Review
As we near the end of 2012, I want to take this opportunity to reflect on our strategy, our progress and our future.
As a Company, we continue to have three main objectives: generate rates of return on invested capital significantly in excess of our cost of capital, achieve moderate growth of the business and deliver continued dividend growth. With regard to returns, we don't believe that a depleting or shrinking business can maintain high rates of return. One can reduce spending to achieve short term higher returns, but these returns would not be sustainable as the Company would deplete. Our business model is to balance the need for growth of the business while maintaining attractive returns. We are currently in an investing phase in many of our businesses where higher than normal portion of our capital is spent on longer-term projects. This year, we expect to spend approximately 25 percent of our total capital expenditures on future growth projects that will contribute to our operations over the next several years. These expenditures include capital for the Al Hosn Shah gas project which is expected to start production in late 2014; capital for gas and CO2 processing plants and pipelines to maintain or expand the capacity of these facilities to handle future production increases; part of the capital for the chemical segment; and other items.
In our oil and gas business, we have built a portfolio of assets that allows us to execute this strategy. Domestically and internationally, we have a mix of both higher return assets and higher growth assets. Importantly, many of our higher growth assets are relatively early in their development, although we have already experienced meaningful success. In the U.S., our Permian CO2 operation continues to be our most profitable business,
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generating the highest free cash flow after capital among our entire portfolio of assets. In contrast, our Permian non-CO2 business is one of the fastest growing assets in our entire portfolio. Since we began significant delineation and development efforts in 2010, we have grown production by over 25 percent. As a result of the significant activity by us and our partners, our Permian acreage where we believe resource development is likely, has grown from our estimate of about 3 million gross acres earlier in the year to about 4.8 million acres in October. Oxy's net share of this acreage grew from about 1 million acres to about 1.7 million acres during the same period. The attached Conference Call Presentation Slide shows our current acreage position in the Permian.
In California, we have a very large acreage position with diverse geologic characteristics and numerous reservoir targets. As a result, development opportunities range from conventional to steam floods, water floods and shales. The drilling costs and expected ultimate recoveries (EURs) also vary for each.
In mid-2010, we shifted our development program to conventional and unconventional opportunities outside of the traditional and more mature Elk Hills areas. As a result, we have experienced strong production growth in these new areas although traditional Elk Hills has experienced some decline. As you can see on the attached Conference Call Presentation Slide, traditional Elk Hills liquids production dropped from 41,000 barrels per day in the fourth quarter of 2010 to 37,000 in the third quarter of 2012. Liquids production growth in the rest of California more than offset this decline during the same period, growing from 49,000 barrels per day to 69,000. Traditional Elk Hills gas production declined from 22,000 equivalent barrels per day to 19,000 during the same period, which was mostly offset by an
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increase in gas production in the rest of California from 21,000 equivalent barrels per day to 23,000.
Recently, we further modified our programs to emphasize oil production in light of depressed gas and associated liquids prices. As a result, gas production in all of California declined in the third quarter of this year. Total California production growth on a BOE basis is slower than we thought it would be, in part due to the Elk Hills decline, permitting issues and more recently low gas prices. On a positive note, overall performance of the new resources has been consistent with expectations, including our unconventional opportunities for which well performance is similar to the type curves we showed you a couple of years ago. I would also note that over the last several years we have spent $370 million on the new Elk Hills gas plant. The plant went into operation in early July and, notwithstanding initial startup issues, is positively affecting our operational efficiency and production including higher liquids yields. The plant operated optimally for about one month last quarter and has been operating as expected since.
We will continue our focus on higher return, low cost opportunities in California, and as I mentioned, this is a very diverse opportunity set. For example, one of the projects we haven't talked about much in the past is a major steam flood project in Lost Hills, where we expect to achieve significant production growth to about 15,000 barrels per day in several years from the current 4,000 per day rate. Total oil in place in Lost Hills is estimated to be about 500 million barrels. Using reasonable assumptions, we expect to recover over 50 million barrels net to Oxy. Our drilling costs in this area average in the low $200,000's per well and we expect to bring this average cost down over time.
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In the Williston basin in North Dakota, we currently have over 310,000 net acres with significant resource potential, which we estimate to be about 250 million net barrels. Our production in the basin has tripled since we entered the area over a year and a half ago. We have recently slowed our drilling activity and significantly reduced our rig count in the basin as a result of cost pressures. While well costs have subsequently declined modestly, we will only increase our rig count when costs come down enough to make returns competitive with the rest of our portfolio. We believe over the long-term, the total resource base in the Williston basin represents a significant opportunity for the Company.
In the Mid-Continent, including our assets in South Texas, we have significantly reduced our gas directed drilling. However, we could ramp up our gas production rapidly and meaningfully if prices for gas and associated liquids improved from their current levels on a sustained basis.
Internationally, our most significant businesses are in the Middle East region where our operations are characterized by limited duration contracts with high rates of return on invested capital during the contract term. Our primary focus in the Middle East is the United Arab Emirates (UAE), Oman and Qatar, which includes Dolphin. Most of our international capital is allocated to these countries and we derive a very substantial portion of our international earnings and free cash flow after capital from Qatar and Oman. Going forward, the UAE, where we are developing the Al Hosn gas project, also is expected to make a significant contribution to earnings and free cash flow.
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The Al Hosn gas project is approximately 61 percent complete and is progressing as planned. This project made up about 11 percent of our total capital program for the first nine months of 2012. While capital spending is running higher for 2012 than our initially anticipated levels, total development capital for the project is expected to be in line with previous estimates. Currently, the Al Hosn project is consuming sizeable amounts of capital during its development phase. We expect to see a significant shift in late 2014 when this project changes from being a cash consumer to a cash generator. Once the project becomes operational, early free cash flow should approximate $600 million annually at roughly current oil prices and conservative sulfur prices. The project has the potential for additional production in later years which would significantly increase its cash flow. We are going to spend approximately $1.2 billion on the Al Hosn project this year. Once the project becomes operational, our free cash flow should increase by the difference between cash consumption and generation. Based on our 2012 capital spend for the project, this would equate to a $1.8 billion increase in cash flow.
Lastly, we are focused on improving returns through a comprehensive effort to reduce operating expenses and improve capital efficiency. As we have indicated in the past, our operating costs have been increasing for some time for a variety of reasons including industry inflation, our desire to take advantage of high product prices by accelerating production through workovers, which pay for themselves over a short period of time, and our rapid recent growth, which causes some short-term inefficiencies. We are embarking on an aggressive plan to improve our operational efficiency across all cost categories, including capital, with a view to achieve an appreciable reduction in our operating expenses and drilling costs to at least
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last year's levels. We believe we will start seeing the benefit of this plan clearly in the first quarter of 2013 and achieve last year's cost levels by the end of next year on a run rate basis. Several initiatives have already begun and we are seeing strong early results. For example, during the third quarter, we reduced our drilling costs by over 15% in parts of Elk Hills. Our goal next year is to reduce well costs by about this amount for the entire business.
Capital Program
I will now turn to guidance for the fourth quarter.
Our fourth quarter capital spending will slow from the third quarter level to a run rate that we believe will be in line with next year's total capital program. Our intention was to reduce capital meaningfully starting in the third quarter. However, this would have resulted in inefficiencies in areas where we have seen positive results, such as the Permian, parts of California and Oman.
As we discussed in prior quarters, we are sharply reducing our pure gas drilling and have more recently cut back our drilling in certain liquid rich gas areas as well. We are also in the process of eliminating our less productive rigs to improve our returns. Our focus on higher-return oil drilling will result in a decline in our gas and, to a lesser extent, associated NGL production in the future.
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Production
Turning to production expectations in the fourth quarter:
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Over the past year, we have achieved our goal of increasing domestic production by 6,000 to 8,000 barrels equivalent per day quarter-over-quarter. We expect our fourth quarter oil production to grow by about this much. However, the expected decline in gas production resulting from the change in our capital program focus I discussed earlier may offset some of the increased oil production on an equivalent barrels basis.
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Internationally, at current prices we expect production to be approximately flat with the third quarter, while sales volumes increase slightly.
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We expect fourth quarter exploration expense to be about $100 million for seismic and drilling in our exploration programs.
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The fourth quarter is typically the chemical segment's weakest quarter. We estimate fourth quarter earnings will be about $140 million, or slightly lower than the third quarter. Along with seasonal factors, weak global demand from the European and Asian economies and rising natural gas costs will keep pressure on margins.
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We expect our combined worldwide tax rate in the fourth quarter of 2012 to increase to about 40 to 41 percent.
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In closing, we believe we have a deep portfolio of development opportunities that will allow us to continue to deliver returns that are 5 to 6 percentage points above our cost of capital. Total return to our shareholders is the combination of appreciation in stock price and dividends. We have long believed that the job of management is to convert earnings that are retained into stock market value. For example, if we retain $1 billion we should be able to give the shareholders at least a $1 billion increase in the market value of the company. Historically, we have generated closer to $1.50 in value for every dollar we kept. This is a challenging proposition over time as the company continues to grow. An old Wall Street maxim is that the market is a voting machine over the short term but a weighing machine over time. We hope that this is true as we firmly believe that our program of investing on a longer than usual (for us) time frame will reap rewards for our shareholders. If for some reason, our investment plans do not generate acceptable stock market results over a period of time, we will return more of our retained earnings to our shareholders.
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 increase our dividends again next year and in the future at a rate that would maximize returns to our stockholders.
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 Capital Employed (ROCE)
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Reconciliation to Generally Accepted Accounting Principles (GAAP)
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2012
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RETURN ON CAPITAL EMPLOYED (%)
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12.6
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GAAP measure - net income
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4,262
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Interest expense
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87
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Tax effect of interest expense
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(30
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Earnings before tax-effected interest expense
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4,319
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GAAP stockholders' equity
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40,474
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Debt
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7,622
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Total capital employed
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48,096
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ROCE - Annualized for the nine months of September 30, 2012
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12.6
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ROCE-ROE