Attached files
| file | filename |
|---|---|
| EX-99.4 - EXHIBIT 99.4 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_4-20130425.htm |
| EX-99.1 - EXHIBIT 99.1 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_1-20130425.htm |
| EX-99.3 - EXHIBIT 99.3 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_3-20130425.htm |
| EX-99.5 - EXHIBIT 99.5 - OCCIDENTAL PETROLEUM CORP /DE/ | ex99_5-20130425.htm |
| 8-K - FORM 8-K - OCCIDENTAL PETROLEUM CORP /DE/ | form8k-20130425.htm |
EXHIBIT 99.2
Occidental Petroleum Corporation
CYNTHIA L. WALKER
Executive Vice President and Chief Financial Officer
– Conference Call –
First Quarter 2013 Earnings Announcement
April 25, 2013
Los Angeles, California
Thank you, Chris.
Core income was $1.4 billion or $1.69 per diluted share in the first quarter of 2013, compared to $1.6 billion or $1.92 per diluted share in the first quarter of 2012 and $1.5 billion or $1.83 per diluted share in the fourth quarter of 2012. Compared to the fourth quarter of 2012, the current quarter results reflected higher realized oil prices, reduced operating expenses in the oil and gas business and higher earnings in the midstream segment, which were offset by lower volumes in the Middle East/North Africa, as a result of planned maintenance turnarounds, and higher DD&A rates.
I will now discuss the segment breakdown of results for the first quarter.
Oil and gas core earnings for the first quarter of 2013 were $1.9 billion, compared to $2.5 billion in the first quarter of 2012 and $2.3 billion in the fourth quarter of 2012. On a sequential quarter-over-quarter basis,
1
higher realized oil prices and lower operating expenses were offset by lower Middle East/North Africa volumes and higher DD&A rates.
Sales volumes in the Middle East/North Africa were lower compared to the fourth quarter of 2012 mostly due to the timing of liftings, as well as the effects of the maintenance turnarounds in Qatar and full cost recovery under a contract in Oman. This reduced our first quarter of 2013 earnings by about $200 million after tax, compared to the fourth quarter of 2012. Costs associated with the turnarounds, pipeline disruptions in Colombia and other factors further reduced our earnings by about $30 million after tax. These lower volumes and costs reduced the oil and gas earnings by approximately $450 million on a pre-tax basis.
Oil and gas production costs were $13.93 per barrel for the first three months of 2013, compared with $14.99 per barrel for the full year of 2012. Lower costs were attributable to our domestic operations, where production costs were $3.37 per barrel lower in the first quarter of 2013 from the full year of 2012, already beating our previous full-year guidance. In our Middle East/North Africa operations, operating costs increased about $2.50 per barrel on a sequential quarterly basis. This increase was due to the planned maintenance turnaround in our Qatar North Dome and South Dome fields and to a lesser extent, the planned turnaround in Dolphin.
The first quarter 2013 total daily production on a BOE basis was 763,000 barrels, which was 16,000 barrels per day lower than the fourth quarter of 2012, and 8,000 barrels per day higher than the first quarter of 2012. Approximately 13,000 barrels of the total sequential decrease in quarterly production came from Qatar and Dolphin where the planned maintenance impacted production. The turnarounds were executed successfully and production has returned to normal levels.
2
|
●
|
Our domestic production was 478,000 barrels per day, an increase of 3,000 barrels per day from the fourth quarter of 2012 and now the tenth consecutive quarterly domestic volume record for the company. Production was 5 percent higher than the first quarter of 2012. Almost all of the net sequential quarterly increase came from production in the Permian. Liquids production was flat compared to the fourth quarter, reflecting a drop in production in our Long Beach operations, resulting from the effect of lower spending under our production sharing contract there and slightly lower production elsewhere in California in the steam flood operations, offset by higher production in other areas, mainly in the Permian and Williston.
|
|
|
●
|
Latin America volumes were 31,000 barrels per day, which was 1,000 barrels lower compared to the prior quarter and 5,000 barrels higher than the same period in 2012. The reduction from the prior quarter was due to a heightened level of insurgent activity.
|
|
|
●
|
In the Middle East/North Africa, production was 254,000 barrels per day, a decrease of 18,000 barrels from the fourth quarter of 2012 and 20,000 barrels from the first quarter of 2012. A planned maintenance turnaround in Qatar reduced production 13,000 barrels per day. The impact of full cost recovery and other factors affecting production-sharing and similar contracts reduced first quarter production volumes by an additional 5,000 BOE per day compared to the fourth quarter of 2012. Details regarding other country-specific production levels are available in the Investor Relations Supplemental Schedules.
|
3
|
●
|
Middle East/North Africa sales volumes were further lower than production volumes in the first quarter of 2013 due to the timing of liftings.
|
|
|
●
|
First quarter realized prices were mixed for our products compared to the fourth quarter of 2012. Our worldwide crude oil realized price was $98.07 per barrel, a 2 percent increase from the fourth quarter; while worldwide NGLs were $40.27 per barrel, a decrease of about 11 percent, and domestic natural gas prices were about flat at $3.08 per MCF.
|
|
|
●
|
First quarter 2013 realized prices were lower than the prior year first quarter prices for crude oil and NGLs. On a year-over-year basis, price decreases were 9 percent for worldwide crude oil and 23 percent for worldwide NGLs. Domestic natural gas prices were higher by about 8 percent.
|
|
|
●
|
Realized oil prices for the quarter represented 104 percent of the average WTI price and 87 percent of the average Brent price. Realized NGL prices were 43 percent of the average WTI price and realized domestic gas prices were 91 percent of the average NYMEX price. For the first quarter of 2012, the comparable percentages were 105 percent of WTI and 91 percent of Brent for oil, 51 percent of WTI for NGLs and 100 percent of the NYMEX price for gas.
|
|
|
●
|
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
|
4
|
quarterly pre-tax earnings by about $30 million. These price change sensitivities include the impact of production-sharing and similar contract volume changes.
|
||
|
●
|
Taxes other than on income, which are generally related to product prices, were $2.63 per barrel for the first quarter of 2013, compared with $2.39 per barrel for the full year of 2012. The 2013 amount includes California greenhouse gas expense of $0.05 per barrel.
|
|
|
●
|
First quarter exploration expense was $50 million. We expect second quarter 2013 exploration expense to be about $100 million for seismic and drilling in our exploration programs.
|
Chemical segment earnings for the first quarter of 2013 were $159 million, compared to $180 million in the fourth quarter of 2012 and $184 million for the first quarter of 2012. The sequential quarterly decrease was due to higher ethylene costs and increased competitive activity, particularly in the domestic caustic soda markets, partially offset by higher VCM and PVC prices. The chemical segment second quarter 2013 earnings are expected to be about $170 million, benefiting from higher seasonal demand in the construction and agricultural market segments.
Midstream segment earnings were $215 million for the first quarter of 2013, compared to $75 million in the fourth quarter of 2012 and $131 million in the first quarter of 2012. Over 70 percent of the 2013 sequential quarterly increase in earnings resulted from improved marketing and trading performance. The remainder of the increase came from improved margins in the gas processing and power generation businesses and higher earnings from foreign pipelines.
5
The worldwide effective tax rate on core income was 38 percent for the first quarter of 2013, which included a benefit resulting from the relinquishment of an international exploration block. Our first quarter U.S. and foreign tax rates are included in the Investor Relations Supplemental Schedules. We expect our combined worldwide tax rate in the second quarter of 2013 to be about 41 percent.
In the first three months of 2013, we generated $2.9 billion of cash flow from operations before changes in working capital. Working capital changes reduced our cash flow from operations by approximately $200 million to $2.7 billion. Capital expenditures for the first quarter of 2013 were $2.1 billion. The first quarter 2013 capital spend was $440 million lower than the fourth quarter 2012, with about half of the decrease in the oil and gas business. First quarter capital expenditures by segment were 80 percent in oil and gas, 15 percent in midstream and the remainder in chemicals. These and other net cash flows resulted in a $2.1 billion cash balance at March 31.
The weighted-average basic shares outstanding for the three months of 2013 were 804.7 million and the weighted-average diluted shares outstanding were 805.2 million. We had approximately 805.6 million shares outstanding at the end of the quarter.
Our debt-to-capitalization ratio was 16 percent at quarter-end. Our annualized return on equity for the first three months of 2013 was 13.4 percent and return on capital employed was 11.4 percent.
I will now turn the call over to Steve Chazen to discuss other aspects of our operations and provide guidance for the second quarter of the year.
______________
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.
6
Occidental Petroleum Corporation
STEPHEN CHAZEN
President and Chief Executive Officer
– Conference Call –
First Quarter 2013 Earnings Guidance
April 25, 2013
Los Angeles, California
Thank you, Cynthia.
Occidental’s domestic oil and gas segment produced record volumes for the tenth consecutive quarter and continued to execute on our liquids production growth strategy. The first quarter domestic production of 478,000 barrel equivalents per day, consisting of 342,000 barrels of liquids and 817 million cubic feet per day of gas, was an increase of 3,000 barrel equivalents per day compared to the fourth quarter of 2012.
We are executing a focused drilling program in our core areas and to date we are running ahead of our full-year objectives in our program to improve domestic operational and capital efficiencies. For example, we have reduced both our domestic well and operating costs by about 19 percent relative to 2012. This is ahead of our previously stated targets of 15 percent well cost improvement and total oil and gas operating costs below $14 a barrel for 2013. While we are still in the early stages of this process and making a longer-term projection is difficult, our goal is to sustain the
7
benefits realized to date, achieve additional savings in our drilling costs and reach our 2011 operating cost levels over time without a loss in production or sacrificing safety. The purpose of these initiatives is to improve our return on capital.
I will now turn the discussion over to Bill Albrecht who will provide details of our domestic drilling programs and of the capital and operational efficiency initiatives we have implemented.
Thank you, Steve.
This morning I would like to share with you the three main objectives of our 2013 domestic program:
First, delineate our core, or anchor, drilling areas in the Permian Basin. We have accumulated more than 1.7 million net acres covering both relatively established and emerging plays in the Permian Basin. This year we are focused on delineating incremental opportunities in established plays as well as testing the potential of many emerging plays.
Second, drive capital efficiency, particularly in our core drilling programs. We believe that the results of our capital efficiency improvement program are not only scalable across our core programs, but that these results are also sustainable.
And third, enhance our cash margins through operating expense reductions.
Turning now to our first objective, our Permian Basin activity. As we have said in the past, under current market conditions, our growth will come largely from oil. The Permian will play a key role in that growth. In 2013, we expect to spend $1.9 billion in the Permian. Approximately two-thirds of this capital will be spent in our non-CO2 business. In this business, we will
8
drill approximately 300 wells, 90% of which will be focused in four plays – the Wolfberry, Yeso, Delaware sands and Wolfbone. The Wolfberry has been a solid, core play for many years at Oxy and represents the largest proportion of our activity. In 2013, we will drill a mix of infill wells in already established core areas, and step out wells in emerging areas of the play. We expect step out wells to pretty much mirror the solid results we have seen in drilling hundreds of Wolfberry wells in the last several years. The Delaware will be about a quarter of our activity in 2013. We are seeing increased opportunity to enhance economics utilizing horizontal drilling and completions to develop established tight-sand reservoirs. We expect to drill 12 horizontal wells targeting the Delaware sands this year. Our emerging Yeso play in New Mexico has demonstrated encouraging results. As a result in 2013, we expect to increase drilling activity by 30 percent from 2012 levels. The Wolfbone play in Reeves County, Texas is the newest of the plays. Throughout 2012, we were able to acquire a meaningful, mostly contiguous acreage position. We drilled a handful of wells in 2012 and will increase our activity this year as we further delineate our acreage position. Because of the multi-pay nature of the play, wells will be mostly vertical at this stage, although we will drill a number of horizontal wells in sweet spots of this multi-pay interval. Early results are encouraging. Thirty-day IP rates are averaging between 170 – 235 boepd, depending on the area. The key to success is a low cost structure. We have been drilling for less than a year in the Wolfbone and have already seen substantial improvements in well costs. As we build infrastructure and establish a steady program, we expect to see further progress in our costs. In addition to these four core programs, we believe we have opportunities in several other emerging plays. We plan to
9
drill 20 to 25 wells testing horizontal potential in the Bone Spring, Wolfcamp and Cline across our acreage position.
I will now turn to our second objective, driving capital efficiency. There are essentially four elements of our overall capital efficiency strategy. These are locking in our drilling programs, modifying well objectives and design, improving operational execution and improving our contracting strategies. We are measuring our progress by comparing our 2013 well costs to 2012 using the 2013 program attributes. In other words, for our benchmark year of 2012, we are using costs that we incurred for the same mix of well locations and types being drilled in 2013. By implementing all four elements, we have already achieved more than a 19 percent reduction in our well costs relative to the 2012 benchmark across our domestic assets. The most important improvements were achieved in the Williston, the Wolfberry, and shale drilling at Elk Hills where costs have dropped by 32, 20 and 22 percent, respectively. Let me describe each of the four elements in more detail.
First, we have found that locking in our drilling programs for appropriate lead times results in significant efficiencies. This has allowed us to have fit-for-purpose drilling rigs in each core area, minimize the number of drill site contractors, and minimize drilling and mobilization times as well as rig move distances. To this end, as we developed our drilling programs for the year, we locked in our drilling plans for two to three months in advance, depending on location, across all our assets. Consequently, we have reduced our rig-down times by 20 percent. For example, in the Williston, our optimized drilling schedule designed to minimize rig mobilizations has reduced move costs by 33 percent.
10
The second element is modification of well objectives and design. For example, in our Wolfberry program, we now run only two strings of casing instead of three, which has saved approximately $250,000 per well. We have also reduced costs by 47 percent per frac stage per Wolfberry well, without any degradation in production. At Elk Hills, in our shale anchor program, we are running mostly slotted liners instead of cemented liners, saving $1.5 million per well, again with no degradation in production. In a number of our programs, we have reduced the amount of gel loading and resin-coated sand, thus reducing completion costs. In short, we are seeing the benefits in the form of reduced drilling and completion times, and reduced and more efficient use of materials and supplies.
Let me now turn to the third element, improving operational execution. While we are making numerous incremental changes in our day-to-day activities everywhere, we have made significant improvements, specifically in the Permian and Williston business units. In both areas, we’re optimizing our use of water in completion operations by using flowback and/or produced water in stimulations, which is generating substantial savings this year. In the Williston, more of the wells we are drilling have been trouble free, particularly due to improved directional tool reliability. Finally, we have made a fundamental change in the way and the extent to which we use contractors and outside consultants to manage and supervise our drilling programs. A heavier reliance on our own personnel for these tasks has already resulted in efficiencies, while providing more growth opportunities for our people.
The last element of our capital efficiency effort is contracting strategies. In this regard, principally in the Permian, Williston, and at Elk Hills, we have reduced our stimulation contract pricing. We have also
11
reduced our fluid hauling costs by implementing a trucking cluster concept, whereby certain trucking fleets are dedicated to specific core areas.
Overall, we have improved our completed well costs in the Williston from an average $10 million per well as recently as four months ago, to $8.2 million currently. We believe we are now top quartile in well costs in the play, and our current goal is to bring average Williston well costs down to $7.5 million. We believe at this level we will have the flexibility to focus on continuing development of our Russian Creek acreage where we plan to drill 46 wells in 2013, concentrating on the “sweet spot” of our acreage there. Our development will be mainly in the Middle Bakken, with other wells testing both the Pronghorn and Three Forks formations. In another one of our anchor programs, the Wolfberry, we have seen sustained reductions in completed well costs, where costs are down from $3.5 million to $2.6 million.
Lastly, I would like to discuss the third objective of our overall domestic strategy, that is, enhancing our cash margins through reductions in operating costs. While our operating costs have also benefited from some of the actions taken for capital efficiencies that I just described, we have taken additional steps specific to reducing our operating costs, especially in the areas of downhole maintenance and workovers, which together make up the bulk of our costs.
I would like to share a few examples with you of the actions we have taken toward achieving our goal. First, in order to optimize our well-servicing rig costs, we are eliminating inefficient workover rigs. While this has caused an overall decline in our workover rig count, we are finding that through better planning and scheduling, we are able to perform a similar number of well-servicing jobs as we did with a larger fleet. As a result, we
12
have not seen any production falloff from these reductions. Second, through a more rigorous review of wells that are repair and maintenance candidates, we have been able to reduce our workover needs by dropping uneconomical wells from our list. These wells will be subject to ongoing evaluations, based on market conditions. Third, we are evaluating the efficiency of our maintenance crews and prioritizing the most efficient ones. Through more direct on-location supervision, more efficient crews, optimized maintenance scheduling to allow better planning, and tighter controls over spending limits and job approvals, we have already been able to reduce our well intervention times and maintenance and workover costs. Fourth, we are also focusing on our surface operations, which constitute another large cost driver, and have been able to achieve efficiencies in our use of chemicals, water handling and disposal activities. Water handling and disposal is a major cost for the Company, therefore it is a key area of focus for us. In some locations, we have been able to find ways to recycle more of our produced water, reducing our sourcing as well as disposal costs, and as a result, handling water in a more environmentally conscious manner. We are also working with our suppliers to address the costs of these supplies and services. In addition, we’re working on optimizing our use of injectants and energy. For example, we are improving our CO2 and steam utilization through ongoing pattern surveillance and evaluation of injectant-to-oil recovery ratios, and we are reducing our energy costs through maximizing the use of self-generated energy and rate renegotiations.
As a result of our efforts, compared to the 2012 levels, our downhole maintenance and workover costs have dropped 36 percent and our overall surface operations costs by approximately 16 percent, contributing to a 19 percent reduction in our operating costs, on a BOE basis, across all our
13
domestic assets. Our total domestic operating cost per barrel dropped from $17.43 per barrel in 2012 to $14.06 per barrel in the first quarter of 2013. We believe our ongoing efforts will yield additional improvements going forward.
I would like to add that the great success we have had to date in achieving our capital efficiency and operating expense reduction goals is the result of implementing literally thousands of small ideas, suggestions and decisions being made every day mainly at the field level. I am extremely pleased that our personnel at every level have stepped up in a big way to achieve our stated goals of achieving 15 percent capital efficiency gains, and so far, exceeding this goal, and reducing our annualized operating expenses by a minimum of $450 million.
While we have made progress in both our capital efficiency and operating cost reduction efforts, we are still in the early stages of this process and, therefore, our data is based on a relatively small portion of our overall program. In addition, we executed a relatively trouble-free drilling program in the first quarter. Nonetheless, given our results to date and our people's efforts in this endeavor, we are optimistic we can sustain and even further improve upon the results achieved to date. I’d like to emphasize that our overarching goal is to make sure we achieve these improvements without in any way compromising the safety of our operations and of our people, and without impacting our growth plans.
I will now turn the call back to Steve Chazen.
14
Thank you, Bill.
With regard to total return to shareholders, in February we increased our dividend 18.5 percent to an annual rate of $2.56 per share, from the previous annual rate of $2.16 per share. We have now increased our dividend every year for 11 consecutive years, and a total of 12 times during that period. This 18.5 percent increase brings the 11-year compounded dividend growth rate to 16 percent per year.
I will now turn to our second quarter outlook.
Production
Domestically, we continue to expect solid growth in our oil production for the year. As a result of the nature and timing of our drilling program, such as steam flood drilling in California, we expect the second quarter liquids growth to be modest with higher growth coming in the second half of the year. In the first quarter of 2013, our base gas production did not decline as much as we had initially expected. Estimating the production for the rest of the year still remains challenging. We expect to see modest declines in our gas production as a result of our reduced drilling on gas properties and natural decline, as well as a number of gas plant turnarounds scheduled in our Permian business the rest of the year.
Internationally, excluding Iraq, at current prices we expect production to be higher in the second quarter, back to around the fourth quarter of 2012 levels, with the increase coming mainly from the resumption of production in Qatar. Iraq's production is directly correlated to quarterly spending levels, which continue to be volatile. We expect international sales volumes also to get back to about fourth quarter of 2012 levels based on our current lifting schedule.
15
Capital Program
The first quarter capital spending was $2.1 billion. We expect the second quarter rate to be higher. Our annual spending level is unchanged and expected to be in line with the $9.6 billion program I discussed on the last call.
As you can see, the business is doing well and we are continuing to make progress on our operational and financial goals. I am very pleased that employees at all levels have stepped up to the challenges we presented to them and are focused on their jobs. We have not seen any significant negative turnover trends in our workforce. As I have stated before, I remain committed to staying through the succession process.
Now we're ready to take your questions about the performance of the business. However, we do not have anything to add beyond our public announcements about the ongoing Board activities and the succession process.
16
|
Occidental Petroleum Corporation
|
|||
|
Return on Capital Employed (ROCE)
|
|||
|
For the Three Months Ended March 31, 2013
|
|||
|
Reconciliation to Generally Accepted Accounting Principles (GAAP)
|
|||
|
RETURN ON CAPITAL EMPLOYED (%)
|
11.4%
|
||
|
GAAP measure - net income
|
1,355
|
||
|
Interest expense
|
30
|
||
|
Tax effect of interest expense
|
(11
|
)
|
|
|
Earnings before tax-effected interest expense
|
1,374
|
||
|
GAAP stockholders' equity
|
40,940
|
||
|
Debt
|
7,624
|
||
|
Total capital employed
|
48,564
|
||
|
ROCE - Annualized for the three months of March 31, 2013
|
|||