Occidental Petroleum Corporation (OXY) Q2 2013 Earnings Report, Transcript and Summary

Good morning. My name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Occidental Petroleum Second Quarter 2013 Earnings Release Conference Call. [Operator Instructions] I would now like to turn the call over to Christopher Stavros. Please go ahead, sir.

Thank you, Christie. Good morning, everyone, and thank you for participating in Occidental Petroleum's Second Quarter 2013 Earnings Conference Call. Joining us on the call this morning from Los Angeles are Steve Chazen, Oxy's President and Chief Executive Officer; Cynthia Walker, our Chief Financial Officer; Vicki Hollub, Executive Vice President and Head of our California Oil and Gas operations; Willie Chiang, Oxy's EVP of Operations and Head of our Midstream business; Bill Albrecht, the President of Oxy's Oil and Gas operations in the Americas; and Sandy Lowe, President of our International Oil and Gas business. In just a moment, I'll turn the call over to our CFO, Cynthia Walker, who'll review our financial and operating results for this year's second quarter. Steve Chazen will then follow with an update on our production growth strategy, progress on our operating costs and capital efficiency initiatives and guidance on our production and capital program for the back half of the year. Certainly, the highlight of this quarter's conference call will come from Vicki Hollub, who will provide a thorough review of our California oil and gas operations, including the abundant opportunities we have to grow that business over the long term while providing strong financial returns. As a reminder, today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied in these statements and our filings. Our second quarter 2013 conference call press release, Investor Relations supplemental schedules and conference call presentation slides, which refer to our prepared remarks, can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Cynthia Walker. Cynthia, please go ahead.

Thank you, Chris, and good morning, everyone. Thank you for taking the time to join us on our call today. During my comments, I'll reference several slides in the conference call materials that, as Chris mentioned, are available on our website. 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 expectation, 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 6 months of 2013, we generated $6.4 billion of cash flow from operations before changes in working capital, and we 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. As I just mentioned, core income was slightly under $1.3 billion, or $1.58 per diluted share. Compared to the first quarter of 2013, the current quarter reflected improved oil and gas results, driven by higher oil volumes, offset by lower earnings in the marketing and trading businesses, largely due to commodity price movements during the quarter, and higher equity compensation expense resulting from an improved stock price. I'll now 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. And as you can see, this was 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 and North Africa business, following the resumption of production after facility turnarounds in Qatar and Dolphin. We also experienced better realized domestic oil and gas prices, although they were offset by lower realized international oil prices. Improvement in domestic realized prices is mainly attributable to the easing of oversupply in the Permian. This significantly improved differentials for our Permian oil production. There was also a modest increase in exploration expense. Moving to Slide 5, you'll see a breakdown of production changes during the quarter. As I mentioned, production was 772,000 barrels per day. This is 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 our California business 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. These events combined to reduce production by about 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 about 8,000 barrels per day. The impact on a sequential quarterly basis was not significant. Overall, while there were a number of events that impacted production this quarter, we see the underlying business is performing essentially as we expected. If you turn to Slide 6, I'll discuss our domestic production in a bit 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 illustrated on the previous slide. And this was an increase of 8,000 barrels per day from the second quarter of 2012. Focusing on our commodity composition, our oil production was essentially flat versus the first quarter, adjusting for the effects of the severe weather in the Permian. Our natural gas and NGL volumes were 5,000 barrels per day lower than the first quarter, excluding the impact of planned gas plant turnarounds. This reduction primarily reflects natural decline in the Mid-Continent due to lower drilling activity and third-party processing bottlenecks in the Permian. In 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. Our overall sales volumes were lower than production volumes during the quarter due to the timing of liftings. The pickup in insurgent activity in Colombia caused a delay in 2 large liftings scheduled around the end of June. In total, delayed liftings reduced the second quarter pretax earnings by approximately $75 million, or about $0.06 per diluted share on an after-tax basis. We expect the third quarter liftings in Colombia to be at their normalized level, barring any pickup in insurgent activity in the third quarter. Our realized prices for the quarter and the comparison to benchmark prices are summarized on Slide 7. Compared to the first quarter, our worldwide crude oil realized price was almost flat. As you can see, the reduction in Brent was offset by improved realizations for our Permian production. We continued to experience weakness in NGL pricing domestically, which contributed to a 4% decrease in worldwide NGL realized prices, while domestic natural gas realized prices experienced a 24% increase, driven by improvement in the benchmark. You'll also note that we updated our 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 6 months of 2013, production costs were $13.66 per barrel compared to $14.99 per barrel for the full year of 2012. The largest improvement was seen in our domestic operations, where production costs were $3.26 per barrel lower in the first month -- first 6 months of 2013 from the full year of 2012. This 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 facility turnarounds in Qatar and Dolphin, which affected the first quarter. Taxes other than on income, which generally relate to product prices, were $2.66 per barrel for the first 6 months of 2013 compared with $2.39 per barrel for the full year of 2012. Second quarter exploration expense was $78 million. We expect third quarter exploration expense to be about $90 million for seismic and drilling in our exploration programs. Now turning to the chemical segment core earnings on Slide 9. Second quarter earnings were $15 million lower than the first quarter. This is 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 the higher seasonal demand and continued strong PPC sales into construction markets. On Slide 10 is a summary of the 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 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. Our worldwide effective tax rate on core income was 41% for the second quarter of 2013, and we would expect that our combined worldwide tax rate in the third quarter will remain at about the 41% level. And finally, on Slide 11, I'll discuss our year-to-date cash flow performance. For the first 6 months, 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 about $200 million, to $6.4 billion. Net capital expenditures for the first 6 months of 2013 were $4.2 billion, of which $2.2 billion was spent in the second quarter. We generated approximately $270 million with the sale of our investment in Carbocloro in the quarter, and we used $225 million for acquisitions of domestic oil and gas assets, of which about $125 million was during the quarter. After paying dividends and other net outflows, our cash balance was about $3.1 billion as of June 30. Our debt balance remains unchanged and our debt-to-capitalization ratio was 15% at the end of the quarter. Our annualized return on equity for the first 6 months of 2013 was 13%, and our return on capital employed was 11%. I'll now turn the call over to Steve Chazen to discuss other aspects of our operations and provide some additional guidance for the third quarter.

Thank you, Cynthia. Occidental's domestic oil and gas segment continued to execute in our liquids production growth strategy. Our first half domestic oil production of 262,000 barrels a day was an increase of about 7% from the first half of 2012 production of 246,000 barrels a day. Second quarter domestic production of 470,000 barrel equivalents per day consisted of 338,000 barrels of liquids and 792 million cubic feet of gas, a decrease of about 8,000 barrel equivalents per day compared to the first quarter. Liquids production decreased slightly due to planned gas 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. Natural decline comprised the bulk of the total domestic production decline. A number of severe storms affecting the Permian region also lowered our domestic production. Second quarter domestic production was generally in line with our expectations, except for the impact of storms. We're 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 cost by 21% and our operating cost by about 19% relative to 2012. This is ahead of our previously stated targets of 15% well cost improvement and total oil and gas operating cost 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, our Executive Vice President in charge of our California operations. Prior to her current role, she ran our Permian enhanced oil recovery, or CO2, business. She will provide details of our strategies for the next couple of years, considering the current California operating environment. She will also discuss the results of our capital and operational efficiency improvement programs. Vicki?

Thank you, Steve. We are a California company, and we 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're 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 2010, we have created 3,000 new jobs, invested over $8.5 billion in the state and paid $900 million in state and local taxes. We're also the largest oil and gas mineral acreage holder in North 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 waterfloods and unconventional. We plan to continue investing in providing energy for the state for decades to come. This morning, I would like to give you a look at the progress we've made in California this year. When we started the year, our overall objective was to position our portfolio for a long-term profitable growth while achieving immediate wins to have a successful year. Our specific goals were: 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 cost to improve our finding and development cost 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-declined 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 fifth 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 to 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 waterfloods or the optimization of existing floods. Another will look exclusively at the aggressive application of the 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've already achieved and drive additional improvements in our cost structure. As you know, we're engaged in a companywide effort to reduce our operating cost 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 we 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've reduced our overall operating expenses by $3.50 per BOE, from $23.20 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 wellsite operators. Improvements and innovations in service operations account for another 35% of the reduction. Activities contributing to these reductions include optimization of the use of chemicals, improved water handling, fuel and power cost reductions and lower rental equipment use. In capital efficiency, we've also improved by about 15% year-to-date compared to the full year 2012. This success was achieved by focusing on 4 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 nonproductive times associated with rig moves and third-party services and helped to reduce our equipment rental cost. Secondly, we've 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've been able to generate significant savings through the application of one or more of these concepts I just mentioned and then apply 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 these ideas are being generated by our people at the grassroots 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 cost 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 the year to allocate a higher percentage of our annual budget to lower-declined projects project, such as our waterfloods and steam floods. For this year, we plan to spend almost 65% of our capital program on water and steam floods, or approximately $625 million on waterfloods, $370 million on steam floods, out of the total $1.5 billion capital. 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 a portion of our capital on oil and gas liquids development, which represent about 99% of our California capital for this year. California has unique opportunities, with diverse and complex geology. This geologic complexity leads to a broad spectrum of hydrocarbon fields and reservoir types. The depth, quality and drive mechanisms of the reservoirs vary across many of the producing basins and within individual basins as well. Those varied characteristics, along with product prices, costs 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 cost that I've 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 30,000 BOE to 550,000 BOE per well, getting us a wide range of opportunities and variability. Given our diverse portfolio of opportunities in California, we have sufficient inventory to sustain the 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. Now I would like to share some highlights about each of those project types, beginning with waterfloods. Waterfloods are among our core competencies. We have several new waterflood projects in progress this year in various stages, from screening to implementation, in addition to a number of floods, where we are engaged in redevelopment, expansion or optimization activities. We will spend most of our waterflood capital to further optimize our most developed project, the giant Wilmington Field, where our Long Beach business unit is continuing to have success in reserves recovery. Wilmington is a long-standing waterflood, where the keys to redevelopment success are effective reservoir characterization, performance surveillance, reservoir 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-play 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. And in others, horizontal wells are drilled to target specific sand intervals within the larger waterflood zone, which have not been effectively swept by the injected water. These wells have an average initial production, or IP, rates of over 3x higher than similar vertical wells at a cost of just 20% more than the comparable wells. We believe there's still significant potential to be realized in the Wilmington field. For example, since we acquired this asset in 2000, proven reserves have steadily grown. In fact, year-end 2012, proved reserves remained slightly higher than 2000 levels despite 12 years of production, resulting in more than a twofold 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 these wells over the next 7 years will deliver reserves of up to 100 million BOE. Just south of Wilmington, we are starting the redevelopment of the Huntington Beach Field with 2 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 to 5 years using the 2 rigs we currently have committed. We expect to add more well locations as we learn more through our reservoir modeling and surveillances, as we have done in the analog Wilmington Field. We believe that we can increase our production from this field by 10,000 BOE per day and develop reserves of at least 50 million BOE. Another significant project for us is the waterflood expansion at Buena Vista Field, where we expect to drill more than 150 wells over the next 5 years. We believe we can increase the Buena Vista production by 4,000 BOE per day and deliver reserves of 28 million BOE. In addition, our Vintage unit, which is the team that manages our San Joaquin Valley and Ventura County waterfloods, gas properties in the Sacramento Valley and unconventional projects outside of Elk Hills, they have several waterfloods in the pilot phase this year, several under evaluation for redevelopment and a long list of potential projects going through the waterflood screening process. In total, we will spend around 40% of our 2013 California capital on waterflood projects that are expected to generate returns, exceeding 20% on average. In addition to waterfloods, our steam flood activities have also been a sizable focus for us 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 used to inject into the reservoir to produce oil. We believe these projects can deliver attractive returns with the 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. The 2 largest steam flood projects for 2013 are in the Kern Front and Lost Hills fields, being managed by our newly formed heavy oil team. These 2 fields contain over 1 billion barrels of oil, original oil in place, on a combined basis, with an estimated 870 million barrels remaining in place. We're in the process of expanding our steam generation capacity in both fields, and these projects are progressing as expected. We have drilled 100 wells in these 2 areas year-to-date. And with the recent addition of 2 rigs, we expect to drill an additional 200 wells in 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 BOE per day by the end of this 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 of production by 15 BOE per day, developing reserves of 120 million BOE. We're also preparing to pilot 2 smaller steam floods in Oxnard and the Midway Sunset Area by the beginning of next year. With the success of these projects, we expect to be able to develop an additional 45 million BOE of reserves. Our total steam flood spending will constitute about 25% of our total California capital in 2013. Over the next 5 years, we expect to drill 1,500 steam flood wells. As we shift capital to greater water and steam flood opportunities, we expect a lag of about 6 to 9 months before we see sustained production growth, as the flow of new projects reaches a steady level. We're in this transition period but are now beginning to see the initial phases of growth from these projects. In addition to shale plays, our unconventional opportunities include those reservoirs that have low permeability and require special recovery processes to flow. Currently, about 1/3 of our California production is from unconventional reservoirs. This year, we plan to drill more than 70 unconventional wells. We have more than 1 million 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 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 a part of continuing development programs that are delivering better than 20% rate of return. Our ongoing program around Elk Hills is expected to increase our ultimate recovery by about 150 million BOE. An example of unconventional opportunities we are pursuing outside of Elk Hills includes drilling and development at the Rose Field. We purchased this field in late 2009 and drilled 1 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 155,000 BOE per well on average. We believe our returns from this field will be around 25% over the course of the development program. We also plan to drill additional unconventional wells in South Belridge and the Buena Vista areas this year. Success in these areas could ultimately provide more than 100 well locations and up to 35 million BOE in net reserves. A discussion of the future potential of California will 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 million BOE, 424.5 million BOE net to Oxy. Now 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're 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 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%. These opportunities include waterfloods, steam floods, as well as potential polymer and CO2 floods that could be implemented over the next 3 to 10 years. These significant operating and capital efficiency improvements made by the Elk Hills team will improve the profitability of these waterfloods and the EOR opportunities. I would also like to point out that our plant operations team at Elk Hills has done a great job of optimizing runtime and reliability from our new cryogenic gas plant. Currently, the team is operating the plant at greater than 90% uptime, and they have extracted record volumes of NGLs from the gas streams this year. Elk Hills still has more than 900 million BOE of remaining reserves and resources that can be recovered through waterflooding and current proven EOR technologies, in which we have considerable expertise, so we're going to continue our development efforts at Elk Hills. 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 100 exploration wells across the California basins in both conventional and unconventional plays. A full 2/3 of our wells have 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 and drilling and testing this year established reserves and resources of approximately 50 million BOE. The full development of this discovery is expected to require drilling 100 wells. In addition to the 50 million BOE we've 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. Our 2013 exploration program, which includes 15 wells, is on track to deliver results consistent with prior years, and we continue to build inventory to ensure we have a robust exploration program going forward into 2014 and beyond. 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 sizable natural gas position, with over 318,000 net acres and 66 million cubic feet a day of dry gas production. We estimate that we operate, through our Vintage business, over 80% of oil 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 wells in 2014. We believe that the range of possible projects that are available in our acreage gives us the ability to ramp up our development efforts with attractive returns at prices around $5 per Mcf. Currently, we have identified total reserves and continued resources of about 300 Bcf. We believe that our acreage held about 10 Tcf of original gas in place, with about 2 Tcf currently remaining. As you can see, we have a large inventory of waterflood, 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 and spending while achieving healthy production growth. In closing, I would like to summarize the progress we have made against the goals we established at the beginning of the year. 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 low 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 over the next 10 years, while earning returns of better than 20%. We've 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 350 BOE, from $23.20 in 2012 to an expected average $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 we'll add more as we continue to evaluate additional acreage and project opportunities. We're working on several new waterflood projects in addition to a number of floods, where we're engaged in redevelopment, expansion or optimization activities. We're 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're 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're continuing our focused exploration in 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. We have a large and diverse portfolio of opportunities available to us across the state. We're very excited about the future of our California operations and the role that it will play in contributing to the company's overall growth. I will now turn the call back to Steve Chazen.

Thank you, Vicki. I'll now turn to our third quarter outlook. Domestically, we continue to expect solid growth in our oil production for the year. Based on nature and timing of our drilling programs this year, such as the steam floods in California and timing of several gas plant maintenance turnarounds in the Permian, we expect the 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 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 increase coming mainly from the Permian and California. We expect modest declines in our domestic gas and NGL 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 pickup in insurgent activity in Colombia and stable spending in Iraq. We expect international sales volumes to increase in the second half of the year and recoup well over half the underlift we've expected in the first half. In the first 6 months, capital spending was $4.2 billion, with $2.2 billion spent in the second quarter. We expect 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 we have previously discussed. The positive effect of our capital efficiency efforts has started 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're continuing to make progress on our operational goals. With regard to our strategic business review, we have presented various options to our Board of Directors. Our review of these operations 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. Finally, an affiliate of Plains All American filed a registration statement yesterday with the SEC for a public offering of interest in Plains' general partner. We own 35% of the general partner's interest, and we expect to monetize a portion as a part of our proposed offering. Now we're ready to take your questions.

[Operator Instructions] And your first question comes from Leo Mariani of RBC.

Just a quick question overall on production. It looks like, just kind of looking at the overall company, going to be sort of flattish in 2013 versus 2012. Obviously, you've got a lot of new initiatives in California going here. Looks like that is going to accelerate next year. I know you guys also increased your Permian rig count earlier in the year. Should we expect much better growth on production overall for Oxy in 2014? And maybe any kind of ballpark number we could look for, for growth next year?

Well, of course, I think the oil production will continue to do well in the back half of the year and into next year because almost all of the drilling is focused on oil. California will do much better as the year progresses and into next year. International production, Iraq aside, sort of flattish because of the cost recovery issues. So if you look at just the oil, I think you'll see reasonable growth and better growth next year. Some of the turnaround -- we won't have the turnarounds we had this year in the plants, so we should do better that way. Gas is a different issue. Gas production, it's hard to justify spending a lot of money on gas production. So on a BOE basis, I think you won't see much out of the gas, probably some decline. But I wouldn't -- I don't think spending money on gas is money well spent at this point.

Any price out there you think you need to spend money on gas?

Vicki talked about $5 in California. California is probably the -- California, maybe South Texas are -- and maybe a little bit in the Peons [ph] are the highest return, but I think you'd probably need around $5 to excite us. I mean, the margins are pretty good in oil right now. I think if you look at sort of $100 oil, you make these huge margins, and so trying to squeeze a few more bucks out of gas, just to make some BOEs strike me as not money well spent.

Okay. And I guess, how about the Bakken? Is that an area where you guys have started to pick up at all, given the strength in oil?

I think Bill can answer that.

Yes, we're right now we're running 5 rigs in the Bakken and adding another rig in August. We'll go up to 6, but I don't see much of an increase beyond 6 rigs for the rest of the year.

Okay. And I guess how about Al Hosn? Is that still on track for production kind of late 2014?

Sandy can answer that.

Yes. The Shah Field gas will come on at the end of 2014. We expect to see pretty much full production in 2015.

Your next question comes from Paul Sankey from Deutsche Bank.

Steve, the comment you made on the strategic business review seems to indicate that -- well, it directly indicates that we won't get the plans until later -- much later this year. I was thinking we would have more of an update on, for example, the Middle Eastern sales process. Potentially, it seems to be that you're teeing up for a California spin here. And then ultimately I thought there was some fairly clear plans about your intentions for the remaining co[ph]. Can you just sort of go back through how we've ended up here with you saying there's now a number of different options and where things may be different from the way I perceived them to be potentially?

Well, one of the things that was easiest was the Plains' partial sale and then ultimately full sale. So there's a fairly large number in that. We didn't say anything had changed. I think as you enter in discussions with people about various things, I think it's best that those discussions not be in the public domain and rather be handled privately. And so when we have a definitive thing to talk about in the Middle East, we'll talk about that when it's definitive. As far as the rest of it goes, you can make your own judgments about California based on what Vicki said.

Yes, so I guess we could continue to consider that, that will become a separate -- a standalone company. That seems to be the way.

Well, it's certainly one of the options. I didn't mean to imply that there were now 400 options. We're just considering various options. And the board has really just been exposed to this in detail at one meeting, and so it will take a little while and we want to consult fully with them and weigh all the alternatives for them. But clearly, some things are going ahead quickly.

And the -- I mean, I guess, we still assume that the overall process needs to be complete before you close your career at Oxy at the end of '14?

Well, that would be my hope, so.

Okay, and just the final -- my final question on this would be the towards the end of the year timing, I guess that's conservative. It just seems that you don't have a huge amount of time to complete this process.

Well, it doesn't mean that the process wouldn't proceed without an announcement. So, I mean, there's some things we could do without -- I'd prefer to announce things that are not ideas but well along in the process. So you could move ahead on any of this without some formal announcement.

Right. And my understanding is that things -- you visited the Middle East, things went well. You may be selling more of the Middle East business than previously. I think it had been the idea of 20% to 30% sales for not less than $25 billion total value. Are those reasonable?

Well, I don't want to comment. I don't want to comment on discussions we might have with those -- over there. The trip went well, and they were very pleased with our people and our operations, and they want us to stay in the region and want to do things to help us stay in the region.

Right. And then my final question is as regards California, it feels a little bit like the movie that we saw in 2010. You described a lot of upside and potential in California at that analyst meeting. It didn't really deliver. We've seen volumes down here sequentially in California. How can we get conviction that this enormous upside potential will be delivered when the recent track record is being -- that we think...

I think actually we're up sequentially this quarter. But now you just have to see the production as it goes.

Your next question comes from Ed Westlake of Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: I guess my first question is just on breakeven. So you gave some numbers for the steam floods, but just on sort of...

Steam floods, you should use that as a ratio rather than exactly those numbers. Edward Westlake - Crédit Suisse AG, Research Division: Yes, yes. But on that...

That wasn't breakeven. That was economically work, so that's different than breakeven. I don't know what the breakeven number is. So basically, what we're saying in California is that those are -- that ratio works, and we would continue to exploit at that ratio. Edward Westlake - Crédit Suisse AG, Research Division: All right. And then what about the nonconventional wells and the waterflood? I mean, any sort of rough range for sort of economically working oil prices?

Vicki?

I would say that for the waterfloods, certainly, we -- those are some of our better margin productions and projects. So our breakeven prices on the waterfloods could go down as oil price is down to probably the $60 to $65 range. Edward Westlake - Crédit Suisse AG, Research Division: Right. And then just on the nonconventional side, I mean, obviously your 7 billion barrels of reserve sounds like a great number. I mean, At the current rate, it probably takes about 200 years to drill that. So when you...

199, I thought. Edward Westlake - Crédit Suisse AG, Research Division: Okay, great. But when you're looking at the types of fields that that's contained, I mean, is it fields like Rose, North Shafter, that area? Is it infill drilling around Elk Hills or is it the deep basin? I'm just trying to get an understanding of what the technical breakthroughs are to actually unlock that at an oil price that works.

First, before Vicki answers, I think you need to understand that we've couched this entire discussion around in the current environment, and those are things other than just oil and gas prices. So Vicki can answer now.

Currently, we only drilled and developed on less than 5% of our unconventional prospective acres, so we're still learning a lot about the Monterey shale. We're in the -- what I would still say is even though we've drilled 1,300 wells, we're learning a lot about the Elk Hills area and the Rose and North Shafter areas. We're taking those learnings and applying those to our evaluations of the remaining potential. And the creation of this technical team that we have and working with our [indiscernible] we expect to be able to start expanding out beyond those areas and expect to see some variability, but we'll be able to apply a lot of what we've learned thus far.

Right, I mean, I think the short answer is for the next year or 2 you'll see the areas that she has pointed out. And then as this thing -- we're looking for higher predictability. And so what you'll see is this thing will build out over time rather than sort of leap over time. Because, again, we're looking for predictability and outcome here, so their cash flows would be predictable going forward.

Your next question comes from Arjun Murti of Goldman Sachs.

Apologies if I'm simply repeating the questions here. But you do talk about 7 billion barrels of opportunity in California. But I guess, it sounds like there's still a lot to study over such a large acreage position. How do we think about how risked that 7 billion is? Is the issue in the pace? And I know the regulatory constraints is one of them, but just that that's sort of an unrisk number and you just had to do a lot more work on it? It's just kind of putting these things together here.

Vicki?

That number is based pretty much on what we've seen in the areas that we've been developing thus far, so that number is taken from the actual performance we've seen in the Elk Hills area, with respect to our shale play there, and also taking into account what we've learned in the Rose and North Shafter area. So we feel comfortable about that number. What we are trying to do is work on techniques to actually improve the percent recovery of the oil in place. And there are some techniques that we think we can start to apply and we're starting to see some success on things that we're implementing thus far, and those are results that we hope to be able to share with you in the next -- in the coming quarters.

That's a great...

I think her answer is that it's a risk number.

Yes. No, I know. I got that. So then, I guess, the pace, on the one hand, there can be regulatory constraints. On the other hand, you're still trying to learn more. I don't know how you can weigh between these 2 things. But I think there's just this ongoing question of why not go faster in these areas?

Neither -- we want to make sure this California company has stable, solid cash flow going forward and the regulatory environment will take a while to develop. This is not North Dakota.

Yes. And then just a follow-up on the strategic business reviews. I think you've said it, Steve, but a lot of companies, when they announce these things, do present basically ideas of what they then want to accomplish. It sounds like, whether it's before year end or some other time frame, it'll be much more conclusionary for you or perhaps much more concrete in terms of what you'll actually be announcing at that time. Perhaps actual sales...

If you look at the PAA action, we could've said something about that a year ago or 6 months ago or something like that. We said it when it was concrete. And the problem with ideas is that you telegraph your attentions to other parties, and without -- and I don't think that's necessarily the right thing to do.

Steve, of your 35% of PAA GP, how much is going as part of this IPO?

I've been told I can't answer that. You have to call Barclays to get the prospectus. So maybe they'll send you one.

Your next question comes from Douglas Leggate of Bank of America.

Steve, back to California. So it sounds like what you're seeing by you want the California business to have stable cash flows...

Stable and growing cash flows.

Right. But if go drill a bunch of wells and then you don't have the permitting, let's assume, is that really what's holding you back from stepping up that program? Is it still permitting?

It's a combination of permitting and technical evaluation. We could certainly, if we had a different permitting environment, we could spend a lot more money, probably not enough to satisfy you, but certainly spend more money. And so I think that this is not -- this is still a very difficult environment. There are bills in the legislature that will have a negative impact on us. And so I think we want to be cautious about what we promise.

So looking at your slide presentation, you're indicating like a $500 million step-up in spending, maybe going all the way up to...

Next year.

And maybe you're going all the way up to spending your cash flow. So what -- where is that...

Hopefully, the money we invest will generate more cash flow, so we really won't spend the cash flow.

Right. But where there is the incremental activity? Is it waterflood, steam flood or is it unconventional?

It's probably going to be mostly unconventional.

Okay. Final one on California. The rates of return, 25% -- up 20%, 25%, I think that's what you said in the slide pack. Considering you have the royalty and given the numbers you've given to us before, like 350,000 barrels a day -- sorry, 250 barrels a day with 250,000 EOR, on the cost that you give us, those returns sounds conservative. What -- is that -- I mean, am I reading something wrong there? Or those numbers -- something changed from the [indiscernible]...

Well, I think first of all, it's not IRRs. It's basically accounting returns. So it won't show up in our financial statements about what's -- as opposed to what shows up in our imagination as IRRs. The IRRs are a lot higher because you get your money back real quick, so they're probably not exactly comparable. We didn't write those numbers to be exact. We just said, well, those are what we have. We're pretty confident being able to deliver.

I see. So it's more like a return on capital type of number.

That's right.

Okay. Very last one for me. I know you don't want to elaborate probably on the restructuring at this point. But can you help us with frame on order of magnitude for how you see share buybacks when you do get to the point where you're going to do a [indiscernible] auction? An order of magnitude would be great.

Well, it just depends on how much is raised. But clearly, as we raise money, a sizable share buyback is an order. I don't think -- I think under 10% wouldn't be viewed as sizable.

Your next question comes from Roger Read of Wells Fargo.

Just following up on California. Given the commentary about spending in terms of the, I guess, call it, more the conventional waterflood, the EOR side, focusing on lower decline rates yet the incremental spending will be on the unconventional side, I mean, how exactly does that reconcile in terms of production growth?

Well, you build the base from your steam floods and your waterfloods. That's what the 1.5 billion area does. Once you've got the base, you can afford to step up the higher decline drilling.

Okay. So that's how California ultimately is going to fund itself?

That's how you would expect California to fund itself.

And would California, if put as a separate unit, however it does occur, would it be -- would it take a percentage of the debt? Would it take on new debt and that would be a way to raise cash for the parent corporation? Any light you can shed on that?

I think it's premature to speculate about what we might do there. That's something that you roll out near the end rather than you start with.

Okay. I'm just trying to get kind of a feeling for where it can all come from. And the last...

Well, it isn't going to -- I mean, if it were separated, it would have a capital structure similar to E&Ps, not a capital structure similar to ours.

Okay. And then my final question, as you've made progress on lowering the OpEx, is there any help you can give us in terms of understanding how much of that is a function of maybe not spending on the natural gas side and NGLs as opposed to spending on the crude side, just given that the overall investment in drilling is clearly continuing to grow on the crude oil here in the U.S.?

Yes. The gas workovers are cheaper. So it's more of a struggle to lower it than, given how oily we are, than, say, somebody who's really gassy. So I think that on a BOE basis, gas would clearly be cheaper. So I think it's more of a structure. I mean, even this quarter, the increase is almost entirely due to energy price increases, electricity and that sort of thing. So I mean, to do this in a very oily company is much more a struggle than it is, say, a gas company. If we look at our pure gas production, the areas that are almost pure gas, I mean, they're doing great on this. They've got really low numbers, but they still don't make a lot of money because the gas price is low so, I mean, their operating costs are really nothing. But it's the oil stuff where you struggle because you've got electricity and other costs that make it really out of your control. So I think given oily nature of the company, I think the people in the field have done a great job.

Okay. And then how much more progress do you expect at this point on the cost reduction front?

Well, we show you the targets in one of the slides. And so it will be -- it can always be lumpy in any quarter. You can have one more or a few more workovers or you can have a field problem. So operating costs can be lumpy in any one quarter, and, again, there's electricity costs really out of our control. But you can see it in the slide.

Well, that's kind of what I was trying to get to. I'm wondering, if you've got some of the items are out of your control, what's within your control? How does that line up with the target?

We continue to do better on the items that are in our control. If we broke out the stuff within our control, you'd see even more of a sharp improvement.

Your next question comes from Faisel Khan of Citigroup.

I just have a few follow-up questions. On Slide 31, you guys talk about the significant discovery in the San Joaquin Basin. I just want to understand the full development that you guys talk about, 100 wells, what's the -- what would be the cost of each one of these wells? Is this the sort of $250,000 per well or is it the $7 million per well sort of cost that you guys talked about?

It's probably neither. Vicki?

Yes, it's more on the $2.5 million to $3 million range for that development. And were starting to drill -- towards the end of this year, we'll be drilling the more appraisal wells.

Okay. And if you could help me a little bit to understand how the permitting process kind of works for all these different play types you've discussed in California. I suppose that when you're drilling in areas you're already producing from, those are sort of easier permits to get. But then, as we move out of these areas, it's kind of more difficult to get sort of those permits. So I guess, for this particular discovery, is it pretty easy to get the permits you need to drill up this inventory and realize this discovery? Or how does that work from play to play?

Vicki, why won't you tell him where we are in the permitting process there?

Yes, for that particular area, because it is a new area, we are in the permitting process, and you're correct. For new areas, it takes longer, a little more difficult. And that's why our current appraisal program has not already begun. However, we're in that process now. We've submitted our permit applications and expect to have the approvals of those by the end of Q3. And worst case, we're thinking Q4, so we should be able to proceed as we expect. But you're right. It's in the new areas that we have the delays.

But we started this a year ago, Vicki? So, I mean, it gives you a feel. So we've got a permit to drill a well or 2 and so once we decided we needed to expand it, it's been more than a year.

So to give you a kind of general sort of rule of thumb, is it from discovery to production of -- or realization of the discovery to production, it's kind of like a year or 2?

A year before you can start.

Okay. And then another year before you can get to full production?

Well, no. You've got a year of doing nothing or very little, testing the wells that you've got. Then you get -- hopefully, get your permit in a year or a little more than a year. And even that isn't necessarily the full field development but it might be close to where you are. You have maybe some quality issues that you have to deal with depending on the size of facilities you want to build. This can stretch on for a while.

Okay. So it sounds like the incubation period is like about 2 to 3 years from...

Yes, I think from when you start and as you -- as the field -- if you're unlucky enough in some ways to find more than you thought, you need to go back for more permits because your production facilities aren't big enough. And that will start another period of study by the state. I think the state is doing the best it can, given the environment in the state, the political environment in the state. I think the state government's doing what it can. But no one should underestimate, even when you're successful, how long it takes to convert it into production.

Your next question comes from John Herrlin of Societe Generale.

Just some quick ones. How much were the well costs at Rose?

The well cost at rose was $3.9 million.

Okay. With respect to your waterfloods, why are you not doing polymer at Wilmington or Huntington Beach? Or you didn't mention that, anyway.

Yes, that's under consideration. Our technical team is looking at the possibility of polymer flooding, not only at Wilmington but also at Elk Hills.

The answer is the plain waterflood at Wilmington is working great. And there's no real -- I mean, that's a true technological victory here over the years. And so I think it's -- before you do heroic things, you ought to do stuff that's sort of simple.

Okay, that's fine, Steve. With respect to your response times, you said 6 to 9 months. I assume water is more -- as layer is more protracted than the steam? Or is that incorrect?

It depends on the type of waterflood. Some are quicker responders than others. But based on what we're trying to develop now, it's looking like 6 to 9 months. But we're, in some areas, we're seeing responses already.

His question really is about water versus steam. Is there any difference?

Right, exactly.

No, the steam, there is a lag there too, because you've got to heat up the reservoir, so that does take a while.

Correct.

Last one for me, Steve. Acquisitions, you haven't spent much this year versus the not-too-recent past. Is it an issue of price or dearth of properties or just your current strategic review?

I think all 3. There are not a lot of properties for sale. You've got a curve -- oil price curve. I think the average oil price in the curve is like $85 for the next 3 years. Meanwhile, the current price is $105 or $104, whatever it is. So that doesn't actually lead to a lot of deals because as you look forward, you're talking about at least the market's expecting $85. The seller's looking at checks for $105. That doesn't actually lead to a lot of closure. There's really not a lot of oil properties or properties that we would be interested in for sale, and given where we are in the overall process, I'm building -- we're building cash for other uses.

At this time, I will turn the floor back over to Christopher Stavros for any final comments.

Thanks for joining us today, and please call us in New York with any follow-up questions from the call. Thanks, again.

Thank you. This does conclude today's conference. You may now disconnect.