ex99_2-20130730.htm

Overall in the second quarter, we continued the trend of solid execution seen in the first quarter. We produced 772,000 barrels per day, essentially in-line with our expectations, adjusting for certain events during the quarter. Our operating cost and capital efficiency programs remain on track. We had core earnings of $1.3 billion or $1.58 per diluted share. For the six months of 2013, we generated $6.4 billion of cash flow from operations before changes in working capital and ended the quarter with $3.1 billion of cash on our balance sheet.

If you turn to slide 3, you’ll see a summary of our earnings for the quarter. Core income was slightly under $1.3 billion or $1.58 per diluted share. Compared to the first quarter of 2013, overall the current quarter results reflected improved oil and gas results driven by higher oil volumes,

Now, I will discuss the segment performance for the oil and gas business and begin with earnings on slide 4. Oil and gas earnings for the second quarter of 2013 were $2.1 billion, an increase over both the first quarter of 2013 and the second quarter of 2012. On a sequential quarter-over-quarter basis, improvements came from higher oil volumes, in particular in the Middle East/North Africa following the resumption of production after facility turnarounds in Qatar and Dolphin. Better realized domestic oil and gas prices were offset by lower realized international oil prices. The improvement in the domestic realized prices is mainly attributable to the easing of oversupply in the Permian, which significantly improved differentials for our Permian oil production. There were also modest increases in exploration expense.

Moving to slide 5. As I mentioned a moment ago, production for the quarter was 772,000 barrels per day, an increase of 9,000 barrels over the first quarter and 6,000 barrels over the year ago quarter. On a sequential quarterly basis, these results reflect the resumption of production in Qatar and Dolphin and growth in California as a result of our drilling program. Elsewhere domestically we saw the impact of natural decline due to our reduced natural gas drilling activity. Also reflected are the impacts of weather and planned gas plant turnarounds in our Permian business as well as insurgent activity in Colombia. Combined, these events reduced production by 7,000 barrels per day during the quarter. Also, on a year-over-year basis, full cost recovery and other adjustments under our production sharing and similar contracts, reduced production by 8,000

If you turn to slide 6, I will discuss our domestic production in more detail. Our domestic production was 470,000 barrels per day, a decrease of 8,000 barrels per day from the first quarter of 2013, driven by the factors on the previous slide, and an increase of 8,000 barrels per day from the second quarter of 2012. Focusing on our commodity composition, oil production was essentially flat versus the first quarter, adjusting for the effects of the severe weather in the Permian. Natural gas and NGL volumes were 5,000 barrels per day lower than the first quarter, excluding the impact of the planned gas plant turnarounds. This reduction primarily reflects natural decline in the Midcontinent due to lower drilling activity and third-party processing bottlenecks in the Permian.

Total sales volumes were 764,000 barrels per day in the second quarter of 2013 compared to 746,000 barrels per day in the first quarter. Middle East/North Africa sales volumes were 31,000 barrels per day higher, mostly due to the timing of liftings, as well as the effects of the first quarter maintenance turnarounds. Overall sales volumes were lower than production volumes during the quarter due to the timing of liftings. The pick-up in insurgent activity in Colombia caused a delay in two large liftings scheduled around the end of June. Coupled with the effect of other timing issues in the Middle East/North Africa, delayed liftings reduced the second quarter pre-tax earnings by approximately $75 million or about $0.06 per share on an after-tax basis. We expect the third quarter liftings in Colombia to be at their normalized levels barring another pick-up in insurgent activity.

Our realized prices for the quarter and the comparison to benchmark prices are summarized on slide 7. Compared with the first quarter, our worldwide crude oil realized price was almost flat as the reduction in Brent during the second quarter was offset by improved realizations for our Permian production. We continue to experience weakness in NGL pricing domestically which contributed to a 4 percent decrease in worldwide NGL realized prices, while domestic natural gas realized prices experienced a 24 percent increase driven by improvement in the benchmark. We have also included updated price sensitivities.

Next, I will cover production costs on slide 8. Oil and gas production costs were $13.40 per barrel in the second quarter. For the first six months of 2013, production costs were $13.66 per barrel compared to $14.99 per barrel for the full year 2012. The largest improvement was seen in our domestic operations, where production costs were $3.26 per barrel lower in the first six months of 2013 from the full year of 2012, which represents annualized cost savings of over $500 million, exceeding our previously stated goals. International production costs have remained fairly consistent with 2012 levels excluding the impact of the facilities turnarounds in Qatar and Dolphin which affected the first quarter of 2013.

Second quarter exploration expense was $78 million. We expect third quarter 2013 exploration expense to be about $90 million for seismic and drilling in our exploration programs.

Turning to Chemical segment core earnings on slide 9. Second quarter earnings were $15 million lower than the first quarter, primarily the

result of lower caustic soda export volumes due to weak economic conditions in Europe, slowing demand in Asia, and reduced demand for alumina in South America. We expect third quarter 2013 earnings to improve to approximately $170 million, benefiting from higher seasonal demand and continued strong PVC sales into construction markets.

On slide 10 is a summary of Midstream segment earnings. They were $48 million for the second quarter of 2013, compared to $215 million in the first quarter of 2013 and $77 million in the second quarter of 2012. The 2013 sequential quarterly and year-over-year decrease in earnings resulted mainly from lower marketing and trading performance driven by commodity price movements during the quarter.

Finally, I will discuss our year-to-date 2013 cash flow on slide 11. In the first six months of 2013, we generated $6.4 billion of cash flow from operations before changes in working capital. This amount includes an approximate $380 million cash inflow from the collection of a tax receivable. Working capital changes decreased our cash flow from operations by approximately $200 million to $6.2 billion. Net capital expenditures for the first six months of 2013 were $4.2 billion, of which $2.2 billion was spent in the second quarter. We generated approximately $270 million of cash from the sale of our investment in Carbocloro in the quarter and used $225 million for acquisitions of domestic oil and gas assets. After paying dividends and other net flows, our cash balance was $3.1 billion at June 30. Our debt outstanding remains unchanged, and our debt-to-capitalization ratio was 15 percent at quarter-end. Our annualized return on equity for the first six months of 2013 was 13 percent and return on capital employed was 11 percent.

Occidental’s domestic oil and gas segment continued to execute on our liquids production growth strategy. Our first half domestic oil production of 262,000 barrels per day was an increase of about 7 percent from the first half of 2012 production of 246,000 barrels per day. The second quarter domestic production of 470,000 barrel equivalents per day, consisting of 338,000 barrels of liquids and 792 million cubic feet per day of gas, was a decrease of 8,000 barrel equivalents per day compared to the first quarter of 2013. Liquids production decreased slightly due to planned gas plant maintenance turnarounds in the Permian, which impacted natural gas liquids production. Plant turnarounds also impacted our gas production, which, coupled with lower drilling on gas properties and natural decline, comprised the bulk of the total domestic production decline. A number of severe storms affecting the Permian region also lowered our domestic

We are executing a focused drilling program in our core areas and to date we are running ahead of our full-year objectives to improve domestic operational and capital efficiencies. For example, we have reduced our domestic well costs by 21 percent 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. We believe we can sustain the 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 Vicki Hollub who will provide details of our California drilling programs and of the capital and operational efficiency initiatives we have implemented. Vicki is the executive vice president of our California operations. Prior to her current role, she ran our Permian CO2 business.

We are a California company and are committed to being a responsible partner in the numerous communities in which we operate, spanning from north of Sacramento to south of Long Beach. We are the state’s largest producer of natural gas and the largest oil and gas producer on a gross operated barrels of oil equivalent basis. We provide locally sourced energy to help Californians cool their homes and drive their cars. Since

We are also the largest oil and gas mineral acreage holder in California with more than 2.1 million net acres in some of the most prolific hydrocarbon producing areas of the state. Our vast acreage position has diverse geologic characteristics and numerous reservoir targets, providing us with development opportunities that range from conventional to steam and water floods and unconventional. We plan to continue investing and providing energy for the state for decades to come.

	—	Deliver a predictable outcome for this year given the constraints of working in California.
	—	Advance projects with solid returns, low execution risk and long term growth.
	—	Reduce our drilling and completion costs to improve our finding and development costs and our project economics.
	—	Reduce our operating costs without affecting production to improve our current earnings and free cash flow.
	—	Build a growing and highly predictable lower decline base of production.
	—	Test out various exploration/development concepts both from a cost improvement and execution predictability perspective.

In 2012, we restructured our business units to create teams organized around the unique characteristics of each of our asset groups, resulting in a 5th business unit dedicated to managing our heavy oil properties. This heavy oil team has added the expertise necessary to accelerate the development of our existing steam floods and evaluate new opportunities.

In addition, we created 3 technical teams to better manage the complex geology of the reservoirs in California: One team is dedicated to the design of new water floods or the optimization of existing floods. Another will work exclusively on the aggressive application of EOR technologies, including steam floods, where they are technically and economically feasible. The third team will focus on unconventional development opportunities to optimize recoveries from the Monterey and other key shale plays in California. We believe this structure gives us the ability to grow our California operations more efficiently, maximize the benefits from the improvement in operating and capital costs that we have already achieved and drive additional improvements in our cost structure.

As you know, we are engaged in a company-wide effort to reduce our operating costs and improve capital efficiency in order to improve our returns. In California, we have significantly reduced operating as well as drilling costs, exceeding our targets, and expect to save at least $175 million this year in operating costs through these efforts. On the last call, we provided a thorough breakdown of the efforts being made in all domestic assets and we have achieved similar success in California.

We have reduced our overall operating expenses by $3.50/BOE from $23.20/BOE in 2012 to an expected average of $19.70 for all of 2013. Almost half of these reductions have been in well servicing as a result of high-grading our well service rigs and eliminating less efficient ones, better planning and scheduling of jobs, reducing lower value adding jobs and adding Oxy supervision through reduction of contract well-site operators.

We have also improved our capital efficiency by about 15% year-to-date compared to the full year 2012. This success was achieved by focusing on four key elements of our capital program. First, we have locked in our drilling programs for a minimum of 2 months and in some areas up to 9 months. This reduced our non-productive times associated with rig moves and third party services and helped to reduce our equipment rental costs. Second, we have revised well designs to more appropriately fit the wellbore characteristics and production expectations for each well. Third, we have optimized drilling equipment and fluids to reduce the time required to drill wells. Finally, we have improved our contracting strategies to incentivize our service providers to optimize overall performance through integrated service applications while reducing unit costs. In many instances, such as in the Rose Field, we have been able to generate significant savings through the application of one or more of the concepts I just mentioned, and then applied those same concepts to other wells across the state, which has allowed us to duplicate the savings.

Many innovative ideas are being generated and implemented by our California teams across the state. As we have stated several times before, many of those ideas are being generated by our people at the grass-roots level, which tend to generate individually modest cost improvements that accumulate to significant amounts across all of our projects as successes are replicated. Our people have embraced this effort and are committed to improve operations of our assets at every level by reducing costs and continuing to improve safety everywhere we operate. While the results we have seen so far are very positive and impressive, we believe that we can achieve even more improvements in both operating and capital costs going forward.

After reviewing our California assets as a whole and taking into consideration market conditions, we adjusted our capital strategy at the start of this year to allocate a higher percentage of our annual budget to lower decline projects such as our water floods and steam floods. For this year, we plan to spend almost 65% of our California capital on water and steam floods or approximately $625 million on water floods and $370 million on steam floods out of the $1.5 billion total. We will spend about 25% of the capital on unconventional projects and the remaining 10% on primary drilling projects. Further, given the market conditions, we have increased the portion of our capital on oil and gas liquids development, which will represent about 99% of our California capital for this year.

within individual basins as well. Those varied characteristics, along with product prices, cost and returns determine the mix of the type of projects to be included in our program each year. The significant strides we have made in reducing our capital and operating costs that I described have given us the flexibility to include a large number of potential projects in our development pipeline. For example, depending on the type of project and location, our drilling costs in California, including completion and hook-up costs, range from $250,000 to $7 million, with expected ultimate recoveries of 30 MBOE to 550 MBOE per well, giving us a wide range of opportunities and variability.

Given our diverse portfolio of opportunities in California, we have sufficient inventory to sustain this strategy in the future, for at least another 5 years, and probably even for 10 years or more, while adjusting the liquids versus gas mix as conditions warrant. We believe this approach will provide the best opportunity for growth of the California operations and make it a significant growth engine for Oxy.

success are effective reservoir characterization, performance surveillance, modeling and advances in directional drilling technology. This year we will drill 135 new wells including 35 horizontal wells targeting attic oil and fault isolated zones within this multi-pay reservoir. In Wilmington, we have used a combination of vertical and horizontal wells depending on the location. Vertical or slant wells can be cost effective in certain locations. In others, horizontal wells are drilled to target specific sand intervals within the larger water flood zone which have not been effectively swept by the injected water. These wells can have average Initial Production or (IP) rates over three-times higher than similar vertical wells at a cost of just 20% more than comparable vertical wells.

We believe there is still significant potential to be realized in the Wilmington Field. For example, since we acquired this asset in 2000, proved reserves have steadily grown. In fact, yearend 2012 proved reserves remain slightly higher than 2000 levels despite 12 years of production, resulting in more than a two-fold proved reserve increase during this period. We currently have an inventory of over 1,000 future well locations in the Wilmington Field. We believe that a successful development program focused on those wells over the next 7 years will deliver reserves of up to 100 MMBOE.

Just south of Wilmington, we are starting the redevelopment of the Huntington Beach Field with two new fit-for-purpose rigs, an onshore rig, which has an enclosure specifically designed for drilling in urban areas, and an offshore rig. We expect both of those rigs to arrive and start drilling towards the end of the year. So far, we have identified 128 well locations to drill which will take 4-5 years using the 2 rigs we have currently committed. We expect to add more well locations as we learn more through our

In addition, our Vintage unit, which is the team that manages our San Joaquin Valley and Ventura County water floods, gas properties in the Sacramento Valley and unconventional projects outside of Elk hills, has several water floods in the pilot phase this year, several under evaluation for redevelopment and a long list of potential projects going through the water flood screening process.

In addition to water floods, our steam flood activities have also been a sizeable focus this year. Our steam floods in California are highly profitable, taking advantage of the gas versus oil price spread allowing us to use cheap gas to generate steam, which is then injected to produce oil. We believe these projects can deliver attractive returns with a combination of gas prices as high as $6 per MCF and oil prices as low as $80 per barrel. Typical rates of return for these projects are expected to be 25% or better.

We have drilled 100 wells in these two areas year-to-date, and with the recent addition of 2 rigs, we expect to drill an additional 200 wells the second half of this year. As a result of our activity in these projects, production from our Heavy Oil Business Unit is expected to increase by around 3,000 BOEPD by the end of the year over our 2013 entry rate. Full development of these steam floods is a multi-year endeavor and we believe that over time we can increase our heavy oil production by 15,000 BOEPD, developing reserves of 120 MMBOE.

As we shift capital to greater water and steam flood opportunities, we expect a lag of about 6 – 9 months before we see sustained production growth as the flow of new projects reaches a steady level. We are in this transition period but are now beginning to see the initial phases of growth from these projects.

We have more than 1,000,000 prospective acres for unconventional resources which we believe contain up to 7 Billion BOE of recoverable reserves. We have drilled approximately 1,300 unconventional wells in California since 1998. More than 1,000 of these have been in and around Elk Hills, including the Monterey and other key shale plays. Our current year plan includes 53 unconventional wells from multiple shale plays around Elk Hills with varying costs and expected performance depending on the well’s location and its particular structure. All of these 53 wells are part of continuing development programs that are delivering a better than 20% rate of return. Our ongoing program around Elk Hills is expected to increase our ultimate recovery by about 150 MMBOE.

An example of unconventional opportunities we are pursuing outside of Elk Hills includes drilling and development of the Rose Field. We purchased this field in late 2009 and drilled one appraisal well in 2011, 8 development wells in 2012 and 6 horizontal wells this year with plans to continue drilling. Results have been very good with average IP rates exceeding our expectations and estimated ultimate recoveries of approximately 155 MBOE per well on average. We believe our returns from this field will be around 25% over the course of the development program.

A discussion of the future potential of California would not be complete without a separate discussion of Elk Hills which we acquired in 1998. At that time, Elk Hills had gross proved reserves of 545 MMBOE (424.5 MMBOE net to Oxy). Our cumulative production since our acquisition in 1998, combined with our current proved reserves is almost double the proved reserves for Elk Hills at the time of the acquisition, which shows that we continue to generate ways to get more out of these reservoirs. And we are not done with Elk Hills.

In recent years, our growth in California has come from projects outside of Elk Hills. This is due to our big challenge at Elk Hills where the underlying base decline rate without any capital expenditures would be around 25%. However, we are now looking at additional opportunities, which we expect will further increase the reserves at Elk Hills and help to mitigate the decline rate, possibly reducing it by as much as 50%. Those opportunities include water floods, steam floods as well as potential polymer and CO2 floods that could be implemented over the next 3-10 years. The significant operating and capital efficiency improvements made by the Elk Hills team will improve the profitability of these water flood and EOR opportunities.

I would like to also point out that our plant operations team at Elk Hills has done a great job of optimizing run time and reliability from our new cryogenic gas plant. Currently, the team is operating the plant at greater than 98% up time and they have extracted record volumes of NGL’s from the gas streams this year.

Our California Exploration program has delivered solid results over the last 5 years since we ramped it up. From 2007 through 2012 we have drilled over one hundred exploration wells across the California basins in both conventional and unconventional plays. A full two-thirds of our wells found hydrocarbons, and a large portion of these successful wells resulted in commercial production. We have been busy over the last few years acquiring 3D seismic over a significant portion of our acreage and this has contributed to our high rate of success. Access to this new seismic data and working closely with our operating groups has allowed our exploration staff to build creative and innovative programs.

Last year, for instance, we made a significant unconventional discovery in the San Joaquin basin. Continued appraisal drilling and testing this year established reserves and resources of approximately 50 MMBOE. The full development of this discovery is expected to require drilling 100 wells. In addition to the 50 MMBOE we have established, we are testing and/or planning wells in late 2013 and 2014 that, if successful, will double this volume. Further, this concept has repeatability and we plan to extend this play through much of our California acreage.

Finally, I would like to briefly touch on our gas development prospects in the state. In the Sacramento basin of Northern California, we have established a sizeable natural gas position with over 318,000 net acres and 66 MMcfd (11,000 Boepd) of dry gas production. We estimate that we operate, through our Vintage Business, over 80% of all production in the region. Our current focus in the area is to optimize our current production mostly with inexpensive workovers and a modest drilling program of 8 new wells in 2013 and 14 in 2014. We believe that the range of possible projects that are available on our acreage gives us the ability to ramp up our development efforts with attractive returns at prices of around $5.00 per mcf. Currently, we have identified total reserves and contingent resources of about 300Bcf. We believe our acreage held about 10Tcf of original gas in place with about 2Tcf currently remaining.

As you can see, we have a large inventory of water flood, steam flood and EOR opportunities in California in and outside of Elk Hills as well as significant upside in unconventional opportunities. All of these opportunities will continue to be an important part of our California development plans for the future and will make California a significant growth asset for Oxy. The mix of projects in the next couple of years will be similar to this year as we continue to commit a larger portion of our capital to lower decline projects to manage our capital program more effectively and control escalation in spending, while achieving healthy production growth.

	—	We are executing a $1.5 billion capital program this year, which takes into account the constraints of working in California. We expect to generate free cash flow after capital in excess of $1 billion. Our program incorporates opportunities resulting from improvements we are already seeing regarding permitting in the state.
	—	We shifted our development program towards a higher percentage of lower decline projects such as our water and steam floods. With continued improvements in permitting, we should be able to grow our capital spend to around $2 billion in 2014, with further increases beyond that, reaching around $2.5 billion annually on a sustainable basis. With this program, we expect to grow at least within the corporate target rates of 5 to 8% annually for the next ten years, while earning returns of over 20%.
	—	We have improved our capital efficiency by about 15% year-to-date compared to the full year 2012. We expect to further improve on these results going forward, which will improve our finding and development costs and returns.
	—	We have reduced our overall operating expenses by $3.50/BOE from $23.20/BOE in 2012 to an expected average of $19.70 for all of 2013. This reduction translates to cost savings of over $175 million for the year contributing to our earnings and cash flow.
	—	We have identified at least 5,500 well locations and will add more as we continue to evaluate additional acreage and project opportunities.

—

We are working on several new water flood projects in addition to a number of floods where we are engaged in redevelopment, expansion or optimization activities. We are taking advantage of the gas versus oil price differences and expanding our steam flood opportunities giving us a highly profitable set of projects to work with going forward. We are continuing our focus on a number of unconventional opportunities across the state, including the Monterey shale, to give us further growth prospects. And finally, we are continuing our focused exploration and 3D seismic acquisition program, which has delivered a high percentage of commercially successful projects, the most recent example being our significant unconventional discovery in the San Joaquin basin.

production growth to occur in the second half of the year. We have achieved the drilling targets we set in the first half of the year. As a result, we expect that our second half average domestic oil production will be about 6,000 to 8,000 barrels a day higher than the first half average, the increases coming mainly from the Permian and California. We expect the modest declines in our domestic gas and NGLs production that we have seen in the second quarter to continue as a result of our reduced drilling on gas properties and natural decline, as well as additional gas plant turnarounds scheduled in our Permian business the rest of the year.

Internationally, we expect more cost pool depletions in our contracts in Qatar and Yemen, which will result in less cost recovery barrels from those locations. However, we expect total international production to be about flat in the second half of the year compared to the second quarter volumes, assuming no renewed pick-up in insurgent activity in Colombia and stable spending levels in Iraq. We expect international sales volumes to increase in the second half and recoup well over half of the underlift we have experienced in the first half.

The first six months' capital spending was $4.2 billion, with $2.2 billion spent in the second quarter. We expect the second half of the year spending rate to be higher. Our annual spending level is expected to be generally in line with the $9.6 billion program I have previously discussed. The positive effect of our capital efficiency efforts is starting to become noticeable in our spending patterns. As a result, we believe there is a reasonable possibility our total spending may be somewhat lower than the program amount I just mentioned while still drilling the number of wells we set out as a goal at the beginning of the year.

As you can see, the business is doing well and we are continuing to make progress on our operational goals. With regard to our strategic business review, we presented various options to our Board of Directors. Our review of these options is progressing well, although it is not yet complete, so the Board will continue to evaluate the alternatives. We expect to have additional information regarding our plans towards the end of the year.

Occidental Petroleum Corporation
Return on Capital Employed (ROCE)
For the Six Months Ended June 30, 2013
Reconciliation to Generally Accepted Accounting Principles (GAAP)



RETURN ON CAPITAL EMPLOYED (%)	11.2%



GAAP measure - net income	2,677
Interest expense	59
Tax effect of interest expense	(21	)
Earnings before tax-effected interest expense	2,715

GAAP stockholders' equity	41,850
Debt	7,626
Total capital employed	49,476


ROCE - Annualized for the six months of June 30, 2013