Good morning, and welcome to the third quarter 2013 earnings release conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session. If you'd like to ask a question during that time, please press star one on your telephone keypad. To withdraw your question, press the pound key. Thank you, Mr. Stavros. You may now begin.
Thank you, Tamika. Good morning, everyone, thank you for participating in Occidental Petroleum's third quarter 2013 earnings conference call. On the call with us this morning from Los Angeles are Steve Chazen, Oxy's President and Chief Executive Officer, Cynthia Walker, our Chief Financial Officer, Willie Chiang, Oxy's Vice President of Operations and head of our midstream business, Sandy Lowe, President of our International Oil and Gas Operations, Bill Albrecht, President of Oxy Oil and Gas in the Americas, and Vicki Hollub, Executive Vice President of Oxy's U.S. Oil and Gas Operations. In just a moment, I'll turn the call over to our CFO, Cynthia Walker, who will review our financial and operating results for this year's third quarter and provide some guidance for the current quarter.
Sandy Lowe will provide a brief overview of our oil and gas operations in the Middle East, focusing on the key countries for Oxy, as well as our strategic objectives for the region. Steve Chazen will follow with a discussion of our strategic initiatives and some of our growth opportunities. As a reminder, today's conference call contains certain 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 third quarter 2013 earnings press release, the 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. Cynthia, please go ahead.
Thank you, Chris, good morning, everyone. My comments will reference several slides in the conference call materials that Chris referenced are available on our website. Overall, in the third quarter, we continued the solid execution seen in the first half. Total company production was 767,000 BOE per day, importantly, we produced 267,000 barrels of oil domestically. This is on track to achieve our second half growth objectives. In addition, with three quarters of successful execution behind us, we are confident that we will exceed the goals we set for the year for operating costs and capital efficiency. We had core earnings of $1.6 billion or $1.97 per diluted share. For the first nine months of 2013, we generated $9.4 billion of cash flow from continuing operations before changes in working capital and ended the quarter with $3.8 billion of cash on our balance sheet.
If you turn to slide three, you'll see a summary of our earnings for the quarter. Core income was approximately $1.6 billion or $1.97 per diluted share. As you can see, this is an improvement over both of the prior quarters. Compared to the second quarter of 2013, the current quarter results reflected improved oil and gas segment earnings, driven by higher realized oil prices and domestic volumes, as well as higher core earnings in the chemical segment and improved performance in the midstream segment, driven by higher margins in the marketing and trading businesses, largely due to commodity price movements. I will discuss the segment performance for the oil and gas business and begin with earnings on slide four. Oil and gas earnings for the third quarter of 2013 were $2.4 billion, an increase over both the second quarter of 2013 and the third quarter of 2012.
On a sequential quarter-over-quarter basis, improvements came from higher oil prices and domestic volumes. Volume increases resulted largely from higher oil production in California, the Permian and Williston, and improved Colombia liftings. Moving to slide five, you'll see a summary of production changes during the quarter. As I mentioned, total production for the quarter was 767,000 barrels per day, a decrease of 5,000 barrels per day over the second quarter, and an increase of 1,000 barrels per day over the year ago quarter. On a sequential quarterly basis, these results reflect domestic oil production growth as a result of our drilling program, as well as a resumption of Permian production following plant turnarounds and weather interruptions in the second quarter.
As you can see, we also experienced an improved environment in Colombia, although disruptions continued to impact production in the quarter, and we've seen the same early in the fourth quarter. MENA production was lower, primarily due to the impact of full cost recovery on our contract in Yemen, lower spending in Iraq, some maintenance in Qatar, and labor issues in Libya. Excluding certain of these impacts and the disruptions in Colombia, our overall international production was in line with our guidance on the last call. On a year-over-year basis, full cost recovery and other adjustments under our production sharing and similar contracts also reduced MENA production by about 7,000 barrels per day. If you turn to slide six, I'll now discuss our domestic production in a bit more detail.
Our domestic production was 476,000 barrels per day, an increase of 6,000 barrels per day from the second quarter of 2013, and an increase of 7,000 barrels per day from the third quarter of 2012. Focusing on our commodity composition, oil production increased 6,000 barrels from the second quarter, driven by California, the Permian, and the Williston Basin. For the first nine months of 2013, our domestic oil production has increased by 13,000 barrels per day. This is a 5% increase versus the same period in 2012. NGL production increased 2,000 barrels per day versus the second quarter. Natural gas volumes were lower by about 11 million cubic feet a day compared with the second quarter, almost entirely in the Permian as a result of third-party processing bottlenecks. Moving to our realized prices for the quarter and the comparison to benchmark prices. You can see the summary on slide seven.
Compared to the second quarter, our worldwide crude oil realized price increased about 6%, primarily reflecting changes in benchmark prices. We experienced improvement in NGL prices domestically, which contributed to a 5% increase in worldwide NGL realized prices. While domestic natural gas realized prices experienced a 14% decrease, driven by the decline in the benchmark. You'll note we also included updated price sensitivities. Next, I will cover production costs on slide eight. Oil and gas production costs were $13.60 per barrel in the third quarter, and $13.64 per barrel for the first nine months of 2013, compared to $14.99 per barrel for the full year of 2012. As you can see, domestic operating expenses increased slightly from the second quarter of 2013. This was due to the timing of certain planned workover activities.
International production costs have remained fairly consistent with 2012 levels, excluding the impact of the facilities turnarounds in Qatar and Dolphin that affected the first quarter of this year. We are very pleased with our performance on operating costs this year and will beat our full-year target. Taxes other than on income, which are generally related to product prices, were $2.61 per barrel for the first nine months of 2013, compared with $2.39 per barrel for the full year of 2012. Third quarter exploration expense was $68 million, and we expect fourth quarter exploration expense to be about $100 million. Turning to chemical segment core earnings on slide nine. Third quarter earnings of $181 million were $37 million higher than the second quarter, primarily driven by strong caustic soda export volumes and lower energy and ethylene costs.
Looking ahead to the fourth quarter, demand for chlor-alkali products is typically lower due to seasonal factors. We expect fourth quarter 2013 earnings to decline to approximately $100 million, driven by these seasonal factors, coupled with lower foreign base company sales income and lower caustic soda spot and export prices. On slide 10 is a summary of midstream segment earnings. They were $212 million for the third quarter of 2013, compared to $48 million in the second quarter of 2013 and $156 million in the third quarter of 2012. The 2013 sequential quarterly improvement in earnings resulted mainly from higher marketing and trading performance, driven by commodity price movements during the quarter. The year-over-year improvement was driven by improved margins in our pipeline and gas processing businesses. The worldwide effective tax rate on core income was 40% for the third quarter.
The lower tax rate than guidance resulted from lower volumes in Libya, where tax rates are significantly higher than our overall effective tax rate. We expect our combined worldwide tax rate in the fourth quarter of 2013 to remain in the 40%-41% range. Slide 11 summarizes our year-to-date 2013 cash flow. In the first nine months of 2013, we generated $9.4 billion of cash flow from continuing operations before changes in working capital. Working capital changes increased our cash flow from operations by $400 million to $9.8 billion. Capital expenditures for the first nine months of 2013 were $6.4 billion, of which $2.2 billion was spent in the third quarter. We generated approximately $270 million of cash from the sale of a chemical investment and used $340 million for acquisitions of domestic oil and gas assets.
After paying dividends of $1 billion and other net flows, our cash balance was $3.8 billion at September 30th. Our debt to capitalization ratio remained at 15% at the end of the quarter. Our annualized return on equity for the first nine months of 2013 was 14%, and return on capital employed was 12%. Last, I'll turn to the fourth quarter outlook. With respect to production, domestically, as I mentioned, we are on track to achieve our second half oil growth average of 6,000-8,000 barrels per day increase over the first half average. Our natural gas and NGL volumes are expected to decline modestly in the fourth quarter due to lower drilling on gas properties and natural decline, coupled with the effect of a major turnaround in the Permian.
Internationally, we expect total production to be about flat in the fourth quarter compared to the third quarter, excluding the impact of insurgent activity in Colombia. We expect international sales volumes to increase in the fourth quarter, recouping the deferred listings we experienced earlier in the year. Our annual capital is expected to be about $9 billion. This is about $600 million lower than the $9.6 billion program we've previously discussed. Of this reduction, approximately $200 million resulted from achieving better than planned efficiencies in our oil and gas program, particularly in our drilling costs. An additional $200 million resulted primarily from the deferral of certain oil and gas facilities and midstream projects into 2014. A further $100 million from lower than planned spending in Iraq.
We are particularly pleased that we are on track to meet or exceed our planned drilling activity levels for the year while spending less capital than planned as a result of efficiency initiatives. I'll now turn the call over to Sandy Lowe, who'll provide an overview of our Middle East North Africa operations.
Thank you, Cynthia. As you are aware, we have had a successful involvement in the Middle East North Africa region for over 40 years. We are active in key major oil producing countries in the region and have formed excellent relationships at all levels. The countries in which we operate include Oman, Qatar, United Arab Emirates, Iraq, Bahrain, Libya, and Yemen. We have a diverse set of projects in the region and manage all of our projects with high safety standards, creating local jobs and development opportunities for people in local communities. Our current producing operations have generated over $20 billion of net free cash flow in the past 15 years, and are currently generating annual free cash flow of around $1.6 billion, excluding the Al Hosn Gas project capital, which is currently running at about $1 billion annually.
We reasonably expect that our Middle East business will generate over $2 billion of free cash flow annually once the Al Hosn Gas project becomes operational. We have invested $9 billion of capital in the Middle East region since 2010. 75% of which has been spent in Oman, Abu Dhabi, and Qatar. We have drilled over 2,500 wells in the region during this time and currently have 37 drilling rigs running. We have also spent $300 million on exploration since 2010. Our projects make a significant contribution to the economies of these countries, employing around 15,000 full-time employees and contractors, not counting the workforce at the Al Hosn Gas project, which is currently over 34,000. We have drilled several types of wells throughout the region. These include onshore oil wells in Oman, offshore wells in Qatar, and sour gas wells onshore Abu Dhabi.
The production from our wells ranges from 200 to 4,500 barrels of oil per day, and our gas rates are as high as 120 million standard cubic feet per day. Our Middle East operations are designed to leverage our technical expertise based in central support groups such as project management, engineering, exploration, and drilling. We apply this knowledge locally to successfully execute our projects. We have used this central support approach effectively in the areas of reservoir characterization, flood implementation, drilling and completion techniques, and management of major projects. This enables us to apply best practices across the region while minimizing the deployment of Western expatriates and maximizing opportunities for nationals in each country. We expect that our net Middle East production for 2013 will exceed 260,000 barrels of oil equivalent per day, representing about 35% of Oxy's total production worldwide.
When the Al Hosn Gas project reaches full operational status in 2015, it should add net production of over 60,000 barrels of oil equivalent per day. Our 2013 Middle East development capital is expected to be about $3 billion, with about 44% spent on water flood projects, 34% on the Al Hosn Gas project, 12% on steam floods, and 10% on primary production. We will drill over 750 development wells this year and plan on around 665 wells next year. Our strategic goals for our Middle East business can be summarized as follows: continue to be a growing, profitable, and vibrant business in the Middle East region. Continue to be a preferred strategic partner with the host countries where we operate. Expand our Middle East area of business by partnering with local investors to secure strategically important growth projects. Continue to successfully execute projects.
Achieve returns in excess of 20% on our invested capital. Continue our investment philosophy where our presence makes meaningful contributions to the host economies and makes a positive difference to the lives of the people in local communities, including increased education and employment opportunities for nationals. We have a strong track record in each of the goals summarized above and believe we will be able to deliver successfully on each of these going forward. In particular, we have developed and nurtured close relationships with key partners in the countries we operate. We have always been respectful of the interests, expertise, and values of the host countries. This philosophy has, over time, led to mutual respect and helped us grow our operations profitably.
I will now provide a brief summary of our operations in three of the key countries in the Middle East region, which collectively make up 70% of our current production, 85% of our income from operations, and nearly all of our free cash flow. We spend about 75% of our Middle East capital in these three countries as well. Oman. We've been present in Oman for 34 years and operate in Blocks 9, 27, and 62 in the north of Oman, and Block 53, which is the Mukhaizna field. We are the largest independent oil producer in Oman and have a highly skilled and loyal national staff. Our Omani staff has grown from 246 in 2005 to 1,858 today. Most of our national employees have developed their skills and experience within Oxy, including opportunities to train and work on Oxy projects in the U.S. and other countries.
As a result, over 81% of our employees are Omani nationals, and Omani citizens now hold most of the high-level executive positions, including the president of our Oman business unit. Oxy's gross production is expected to be about 230,000 barrels of oil equivalent per day in 2013, with a net of 76,000 in Oman. Our Omani operations are a significant free cash flow generator. We expect to continue to achieve returns well in excess of 20% from our Oman projects. Northern Oman. In Northern Oman, a combination of development wells, exploration success, and the application of water-flooding techniques has led to an increase in gross production from 92,000 to 106,000 barrels of oil equivalent per day since 2010. We have a large pipeline hub and gas plant at Safah associated with the producing wells in Northern Oman. This infrastructure enables us to rapidly and efficiently bring new wells into production.
Most wells initially free flow and later have either gas lift or electric submersible pumps installed. We have maintained our gross average operating cost at around $5.50 per barrel, with the key drivers being downhole maintenance, surface operations, and support costs. We have drilled 107 out of our 153 planned wells for this year. These are typically horizontal wells with lateral lengths of between 1,800 and 3,500 feet. Recent production rates have been as high as 3,800 barrels of oil equivalent per day, with an average for 2013 of around 550. During 2014, we plan to drill another 125 development wells. Over the next five years, our plans include drilling 400 development and water injection wells. We expect our annual drilling capital to be between $250 million-$300 million per year.
We believe our development program will increase gross production to about 125,000 barrels of oil equivalent per day during this period. Our exploration program in Northern Oman has been one of our most successful ever as a company, with a discovery rate of greater than 60%. We attribute this success to our use of technologies such as horizontal drilling, state-of-the-art 3D seismic, as well as the development of new play concepts. Our discoveries this year, mostly coming from horizontal wells, have an average production of 3,000 barrels of oil equivalent per day and produce over 70% oil. We continue to expand our technical understanding and have a robust inventory of future drilling prospects. In addition, we are nearing completion of a 2,000 sq mi 3D seismic program, which should further enhance our growth portfolio.
This new seismic data over Blocks 9 and 27 should yield many attractive prospects and enable us to continue exploring in these areas for many years. Over the next five years, we expect to drill more than 50 exploration wells, 13 of which are planned for 2014, and to generate more than 250 new development drilling locations. Our Block 62 development is in the early stages of engineering, with a number of gas producers already drilled. We are planning to further delineate one of the larger structures by the end of this year, allowing an updated development plan to be presented to the government during 2014. Mukhaizna. Mukhaizna is one of the world's largest steam flood projects. At the end of 2012, it ranked third in the world in terms of steam flood production, ahead of the large, best-known U.S. steam floods.
Oxy's involvement in the Mukhaizna field began in 2005. Since that time, we have increased gross production from 8,000 to 125,000 barrels of oil per day and produced 160 million barrels of oil from the field. We have drilled over 2,000 wells, of which 825 are producers. The steam wells enable injection of over 500,000 barrels per day. Waste heat recovery systems on power generators account for 20% of our steam. We continue to optimize the development plan of this field with the government and our partners, and we expect to continue executing our infill drilling program. The anticipated peak production is estimated to be between 135,000 and 140,000 barrels of oil per day. We expect to drill 340 wells this year. Recent rates have been as high as 830 barrels of oil per day, with an average for 2013 of around 330.
We plan to drill another 300 wells in 2014. We currently have six rigs running in Mukhaizna. In addition to the main Mukhaizna reservoirs, we are delineating the extensive Kahmah fractured carbonate heavy oil reservoir, which lies above the main pay in Mukhaizna. We presently have one rig dedicated to this activity. Another milestone will be reached in Mukhaizna next year with the drilling of our first deep exploration well in the field. Qatar. We presently operate three shallow water offshore oil fields in Qatar: the Idd El Shargi North Dome, the Idd El Shargi South Dome, and Al Rayyan. We also have an interest in the Dolphin project, which has been a great success since its start. Through our plans for various projects in Qatar, we expect to achieve returns well in excess of 20%.
In nearly 20 years in Qatar, we have invested $4.3 billion and produced 680 million barrels of oil. Our operations in Qatar provide significant free cash flow. Current production is around 106,000 barrels of oil per day for 2013 from the three fields, netting 67,000 barrels of oil per day to Oxy. Dolphin's current production net to Oxy is about 38,000 barrels of oil equivalent per day. In Qatar, as in Oman, we are focused on the development of national staff and have successful national employees in all levels in the company. Oxy has established itself as an active and committed member of the community. During our presence in Qatar, we have forged strong and effective relationships with a number of organizations in the focus areas of health, education, arts and culture, and sports.
Examples include partnering with the Supreme Education Council and the Weill Cornell Medical College in the promotion of a healthy lifestyle, which is aligned with Qatar National Vision 2030. Other initiatives relate to specific causes such as diabetes, cancer, working with the Al Noor Institute for the Blind, and partnering with the Qatar Museums Authority in supporting a number of sporting events. In Idd El Shargi North Dome, we will drill 17 wells in 2013 from jackup rigs in a water depth of around 130 feet. Over the course of our involvement in Qatar since 1994, we have drilled 268 horizontal producing wells and over 100 horizontal water injectors. Recent well production rates in Idd El Shargi North Dome have been as high as 4,500 barrels of oil per day with an average for 2013 of around 1,460.
As part of our recently approved phase 5 development plan, we will drill another 205 wells at a cost of $1.2 billion. We plan to drill 36 of these wells in 2014. The development plan includes the installation of new wellhead platforms, a compression and power platform, and various pipelines and related facilities. We believe that as a result of this development, we will be able to continue the plateau gross production of 100,000 barrels of oil per day for many years to come. We also have new development opportunities being planned for the Idd El Shargi South Dome and Al Rayyan fields. Dolphin. The Dolphin Project remains one of the flagship projects in the region, and it has been a great success since coming on stream in 2007. The project involves production from wells located on two offshore platforms in the North Field of Qatar.
Wet gas flows to the onshore gas plant at Ras Laffan, where we process it into condensate, natural gas liquids, and sulfur. The dry gas is exported under a long-term contract to the U.A.E. via a 48-inch, 230-mile subsea pipeline. In addition to the two billion cubic feet a day of contracted gas from Qatar, we transport additional gas on an interruptible basis to customers in the U.A.E. While meeting a significant portion of the U.A.E.'s gas needs, Dolphin also provides gas to Oman. We are currently expanding gas compression facilities in Ras Laffan to achieve the maximum pipeline capacity of 3.5 billion cubic feet per day to handle additional volumes. We believe substantial opportunities remain in the region to sign up additional customers to provide gas transportation up to the full capacity of the Dolphin pipeline, generating additional midstream revenues and cash flows.
We expect our 2013 net production from Dolphin to be around 38,000 barrels of oil equivalent per day with significant free cash flow, which we believe will grow over time as we take on new customers. United Arab Emirates. Oxy's initial experience in the U.A.E. was as a partner in offshore exploration during the '60s. Most recently, Oxy has had a presence in the U.A.E. since 2000. Since then, our Abu Dhabi office has developed into a regional hub supporting our Middle East assets with engineering, geoscience, business development, operations, supply chain, and finance resources. During this time, the Dolphin midstream infrastructure has continued to expand, and the pipeline system now extends for 475 miles throughout the U.A.E. and into Oman.
The Al Hosn Gas project, where we are partnering with the Abu Dhabi National Oil Company, ADNOC, involves the development of the Shah sour gas field in the western region of Abu Dhabi. Production from the field contains natural gas and condensate, along with high concentrations of hydrogen sulfide and carbon dioxide. A large processing plant is currently under construction with an average 34,000 workers at the site. This is a world-scale mega project with the involvement of major engineering, construction, and manufacturing companies from around the world. It remains on schedule and on budget. When completed, the plant will be able to process about 1 billion cubic feet a day of gas from the field and separate it into sales gas, condensate, Natural Gas Liquids, and sulfur.
Oxy's net share of production is expected to be over 200 million standard cubic feet a day of sales gas and more than 20,000 barrels of NGLs and condensate. By the end of 2013, the project will be about 92% complete and will start up next year. The 2013 Oxy share of Al Hosn capital is expected to be about $1 billion. Total project cost is expected to be on budget at about $10 billion, with Oxy's share of $4 billion. We expect production from the project to start in the fourth quarter of 2014. Once the field achieves steady state, annual average free cash flow to Oxy should be approximately $600 million at current liquids prices. Currently, we are spending about $1 billion per year, so steady state operation should provide a net cash flow swing of $1.6 billion annually.
As we have recently announced, we are currently looking to sell a minority interest in our Middle East North Africa operations. We believe this will give us an exciting opportunity to possibly partner with key regional players. This sale will reduce the Middle East North Africa share in our overall portfolio. We believe a partnership with regional investors will align us with local interest in our existing operations and on new opportunities throughout the Middle East to achieve future growth from a lower base. In summary, we believe we are well positioned to meet each of our strategic goals in the region. Specifically, we have a highly profitable, vibrant, and growing business. We have developed strong and lasting relationships with host countries where we are welcome and invited to stay. We will continue to be a preferred strategic partner to them in the years to come.
Our plans to sell a minority in our Middle East North Africa operations will assure that we will continue to grow our Middle East North Africa business profitably over time by securing strategically important future projects. Our development and operating plans will ensure continued success in executing our projects. We will continue to achieve returns in excess of 20% of our invested capital. We are continuing to apply our investment philosophy where our presence makes meaningful contributions to the host economies and makes a positive difference in the lives of the people in the local communities, including increased education and employment opportunities for nationals. In closing, I would like to emphasize, we are very excited about our presence and our opportunities in the Middle East.
We believe that our excellent relationships and partnership with key regional players, coupled with our long regional experience and our track record of timely project execution, will allow us to continue to enhance our rich growth potential of the region. I will now turn the call over to Stephen Chazen, who will discuss our strategic initiatives.
Thank you, Sandy. Earlier this month, we announced the initial phase of the company's strategic review as a part of an effort to streamline and focus our operations in order to better execute the company's long-term strategy and enhance value for our shareholders. As a result of the initial actions, Oxy's board of directors has authorized the following: to pursue a sale of minority interest in the Middle East North Africa operations in a financially efficient manner, as Sandy just discussed. pursue strategic alternatives for selective mid-continent assets, including our oil and gas interests in the Williston, Hugoton, Piceance Basin, and other Rocky Mountain assets, and the completed sale of a portion of our 35% interest in General Partner of Plains All American Pipeline. This resulted in pre-tax proceeds of $1.4 billion. This initial sale process was concluded, and we've received the proceeds.
Our cash balance of $3.8 billion at the end of the quarter does not include these proceeds. Oxy's remaining interest in the Plains All American Pipeline, based on the IPO price, is valued at approximately $3.3 billion. As we indicated, these are our first formal steps in our effort to streamline the business, concentrate in areas where we have depth and scale, and improve overall profitability. Our goal is to become a somewhat smaller company with more manageable exposure to political risk. We will continue to seek additional strategic alternatives for the company to maximize total returns to our shareholders. These actions are expected to generate a significant amount of proceeds. Together with the excess cash in the company's balance sheet, these funds will largely be used to reduce Oxy's capitalization.
While we expect to use a substantial and a vast majority of these proceeds to repurchase our shares, we also anticipate paying down some of our debt on a proportional basis. We expect to retire $600 million of bonds due in December. We also expect to reinvest a portion of these proceeds in high-return growth opportunities throughout the business, several of which I will discuss in a moment. We continue to make steady progress and expect to complete the strategic review in the coming months, and we'll disclose material developments as they occur. Approximately a year ago, our oil and gas business embarked on an aggressive plan to improve our operational efficiency across all cost categories, including capital. They're geared to achieving an appreciable reduction in our operating expenses and drilling costs. Our teams are to be commended for doing a superb job on this front, exceeding our initial goals.
We continue to run ahead of our full-year objectives to improve domestic operational and capital efficiencies. For example, we have reduced our domestic well costs by 22% and operating costs by about 18% relative to last year. This is ahead of our previously stated targets of 15% well cost improvement and total oil and gas operating costs below $14 a barrel. Total annualized savings from these operating costs and capital efficiency initiatives amount to $1.2 billion compared to last year. We expect these savings to result in additional development opportunities as previously marginal projects are now economic. The purpose of these initiatives is to improve our return on capital while continuing to execute a focused drilling program in our core areas and grow our domestic oil volumes.
The benefit of these cost savings cannot be overstated, as they will result in a year-over-year improvement in our F&D costs, leading to a more stable DD&A rate. We believe we can sustain the benefits realized to date, achieve additional savings in our drilling costs, and reach our 2011 operating cost level over time without a loss in production or sacrificing safety. We are particularly pleased that we are on track to meet or exceed our drilling activity levels planned for the year while spending less capital than planned as a result of these efficiencies. These achievements have generated higher margins, giving us confidence to allocate additional capital towards our profitable growth opportunities. As Vicki discussed in last quarter's call, we are the largest oil and gas mineral acreage holder in California.
With more than 2.1 million net acres, we have a large and diverse portfolio of opportunities available to us across the state. We've reduced our overall operating costs in California by more than $4 a barrel equivalent to an expected average of under $19 for all of 2013. Improvement in our operating as well as our drilling costs has exceeded our targets and should allow for combined savings at least $300 million this year compared to 2012. As a result of these improvements and combined with more favorable permitting, we plan to increase our capital spending in California by about $500 million to approximately $2.1 billion next year. Most of this increase will be directed towards unconventional drilling opportunities where we have more than one million prospective acres for unconventional resources.
In the Permian Basin, we've accumulated more than 1.7 million net acres covering both relatively established emerging plays, anchored by our core high free cash-generating CO2 flood reservoirs. We have recently created an exploitation team whose mandate is to optimize our drilling capabilities and accelerate the development of unconventional opportunities throughout the basin. This year, we have focused on delineating incremental opportunities in established plays, as well as testing the potential of many emerging plays, which included the drilling of approximately 30 horizontal wells. We've also succeeded in reducing our drilling cost by more than 20%, which has increased our ability to enhance our economics utilizing horizontal drilling and multistage completions to develop established unconventional reservoirs. As a result of these efforts, we can now shift our development strategy and expect to spend an additional $500 million in capital next year, largely directed towards increased drilling horizontal wells.
This step up in capital will allow for additional four rigs, which will be dedicated to drilling horizontal wells in our focus plays of Wolfcamp, Bone Spring, and the Delaware Basin, as well as the Wolfcamp and the Midland Basin. As an example of this, we recently completed a well in our South Curtis Ranch area, which is near our Mabie acreage. It was completed in the Wolfcamp D and is tested just over 1,000 barrels of oil a day, 77% of which is oil, 15% NGLs, with a small amount of remaining natural gas. We have over 17,000 net acres that is prospective for this in the area. This represents a major change in our Permian non-CO2 development strategy, in which the number of horizontal wells drilled next year will account for more than 50% of total wells, compared to only 10% during 2013.
Turning to our international operations, our 30-plus-year history of operating in Colombia has provided us with a unique insight around heavy oil production, mature oil field development opportunities. Historically, this has been among Oxy's most profitable operations. The experience associated with steam flood development is a core competency at Oxy, a skill set that fits well with Colombia's strategy to grow its crude oil production. Going forward, we plan to focus our efforts on applying our expertise for the pursuit of high additional, high return oil redevelopment projects, and we expect to participate in several more steam flood projects in the coming years. In our Middle East North Africa business, and as Sandy discussed, majority of the value of our production income and cash flow is derived from three key countries, Oman, Qatar, and UAE.
Majority of our regional capital is also deployed in these countries, and we expect our MENA business will generate more than $2 billion a year of annual free cash flow after the Al Hosn Gas project becomes operational. We feel fortunate to have had many successful years operating in the region. Part of this, we believe is a result of successfully executing on a number of challenging projects. We also feel that it's in part due to the mutual respect we have for our partners, the host countries in which we operate, and for the people who reside there. Although the sale of a minority interest will reduce our share of MENA within our overall portfolio, we expect to remain a major participant in the region with a focused presence.
Our track record of success and strong relationships should allow us to compete for new projects and provide us with future growth off a smaller base. We look forward to forging new partnerships in the region, which will allow us to continue our profitable growth strategy. Opportunity for high growth is also present in our chemicals business, where we plan to pursue a 50/50 joint venture with Mexichem to build a world-scale ethylene cracker at the OxyChem plant in Ingleside. As a part of this long-term strategy, strategic supply relationship between companies, essentially all the ethylene produced in the cracker will be consumed by Oxy in the manufacture of vinyl chloride monomer, utilizing our existing VCM production capacity. The VCM will then be delivered to Mexichem to produce polyvinyl chloride, PVC, and PVC piping systems.
Using the cracker, OxyChem's overall operations effectively consume more than one-third of Oxy's domestic gas and NGL production. A significant benefit of this project is that it provides a higher level of integration from the wellhead through to VCM production and sales. The project is just one example of several we plan to pursue in our effort to capture greater value in the downstream portion of natural gas in the NGL trains versus an independent upstream gas producer. Construction of the Ingleside cracker project is expected to begin in mid-2014, with facilities becoming commercially operational in 2017. We expect it to have a material benefit on our chemical earnings. OxyChem is also expected to continue to be a free cash flow positive throughout the investment phase of the project. In the midstream segment, our investment in the BridgeTex pipeline continues on track for a scheduled startup in mid-2014.
The roughly 450-mile-long pipeline will be capable of transporting approximately 300,000 barrels a day of crude oil between the Permian region and the Gulf Coast refinery markets. We are confident these and other opportunities deploy our capital will be meaningful drivers of our earnings growth over the coming years. I think we're now ready to take your questions.
Tamika, can you please poll the questions?
If you would like to ask a question, press star one on your telephone keypad. Your first question comes from the line of Doug Leggate with Bank of America Merrill Lynch.
Thanks. Good morning, everybody. Steve, I've got a couple-
Hi, Doug.
if I may. Good morning. Starting with the Middle East, there's been a lot of speculation over the potential value that may or may not be associated with this asset. I know you can't give specifics, but could you frame for us, given the relative lack of transparency in terms of, you've done a good job today laying out the businesses, but reserve bookings and so on are still somewhat lacking transparency. Can you help frame for us what you think a realistic, acceptable range of value might be, and whether or not the midstream would be part of that? I've got a couple follow-ups, please.
Yeah. The Dolphin project would be part of the sale process. That piece of our midstream business would be part of that sale. There are confidentiality agreements between the three major in each of the countries, so you can't actually give you more transparency without violating the confidentiality agreements. For example, we can't tell you the details in Oman or Qatar or Abu Dhabi. I think it's fair to say that we book only to the life of the lease, and as the extensions come, obviously more reserves come. We also depreciate basically over that life, so the earnings are somewhat understated. I think if you look at the cash, we view it as an ongoing business. That is to say, it's not just a pile of assets that we're going to deplete.
To the extent it's an ongoing business, we expect to receive a price that reflects the value of an ongoing business, not the price of a depleting asset or the reserves that are necessarily the reserves are there. The countries can see the long-term reserves, I don't think there's a lot of issue with them not understanding what the long-term outcome is. I don't really want to negotiate with myself on the values.
Okay. A related question, Stephen, on the buybacks, the potential. There's been a number bandied around in the press of $8 billion from the Middle East, let's assume that was reasonable. I believe there are some tax issues around what you can bring back as an optimum level. If we then look at Plains and potential Midcontinent sale, can you help frame for us what you see the scale of the buyback would be? If I may just add something to this. Acquisitions in the Permian Basin seem to have slowed down. I guess valuations have got something to do with that. You're generating a lot of cash. How should we think about buybacks on a go-forward basis to maybe enhance your per-share growth?
I think buybacks will be an important element of per share growth certainly in the next few months. We have a lot of cash on the balance sheet. We had $3.8 billion at the end of the quarter, plus the money from the sale of midstream assets. We would expect to begin a repurchase of some shares shortly. As far as the scale goes, we're not going to build cash. We're not going to pay down. Debt reduction will be proportional. If we sell 10% of the assets, maybe the debt will go down 10%. We only have about $7 billion of debt, it's not going to be a big user. These projects will probably allow us to still stay within our cash from operations next year, it's probably not going to drain a lot.
As far as acquisition is concerned, I think the issue in the Permian is there's just not a lot for sale, that which is for sale isn't all that interesting. We have a lot of acreage. I've just highlighted just one small area where we're doing well. We've got a lot of acreage, the need to drive the business through large-scale acquisitions is pretty modest at this point. You should expect the bulk of the proceeds to go towards per share repurchases. Anything else, we're not going to build cash. I can't tell you exactly the number. One of the reasons why once we can frame this more clearly as to how much money is involved, then we can talk about the last steps in this. I think we need to see where we are. Our goals are really twofold.
We need to make sure we continue to operate well because that's really what drives value. We need to execute the things we've announced. I think that's what we're trying to do. Once we get that at least in sight, we'll talk about the further restructuring steps.
Okay. One last one from me-
Is that helpful or not?
I guess we're lacking specifics, Steve. Obviously, I think the market's kind of telling you that we're lacking specifics. I guess we'll have to wait until you can give more color. If I could try one final one, if I may. Your press release the other day failed to mention California. It continues to be a drag and frankly, a serial underperformer, I guess, in the eyes of the market. What are the parameters that you think may or may not contribute to your decision on whether or not California can do better on its own? I think that is clearly one of the key gating items for the market's view on the restructuring on a go-forward basis. I'll leave it there. Thanks.
Yeah. I think we go back to this question about what. You could come up with a very high number without me telling you exactly what it is for the share repurchase. You might be off a billion or two, but that's about all. You could use the numbers that are floating around out there. You could guess what the proceeds from the Midcontinent sale would be within a few hundred million dollars. You can obviously see how much cash we have now. I don't think anybody should be off very much in computing how much the share repurchase would be. The debt reduction, the other stuff is not large in comparison to that. As far as California is concerned, the fundamental question is, can it operate better as a standalone business with a different model?
The different model, if it's going to operate just like it does now, then it might be better off staying the way it is. If it can operate better with a different model, that is a higher capital model, basically little or no dividends, and with a more entrepreneurial background, then I think that it'd be better separated from the company. More to the point, I think, is that separating California from the rest could enhance the visibility and the attractiveness of the remaining business. I think that's clear enough for now. Once we get some slightly better numbers on the proceeds of these two areas that we're working on now, then we can size California if we're going to do it appropriately.
Thanks for taking my questions, Steve.
Thanks.
The next question comes from the line of Doug Terreson with ISI.
Good morning, everybody. Congratulations on your results.
Thank you.
Yeah. Steve, you highlighted on some of the strategic review slides a major change in strategy in the Permian today that's going to be driven by this new exploitation team. On this point, I wanted to see whether you could provide some color or whatever color you might have on this new unconventional drilling group in the Permian. Also, you also just mentioned a few minutes ago about the Plains All American position. The question there is whether there's any strategic or operating rationale as to why the remainder may not be divested in the future. Two questions.
Yeah. The second one is easy to say. It'll be divested in the future.
Thank you.
When we entered into it was a private business.
Yep.
I don't have any problem investing in a private business that shareholders can't access if I think it makes sense for us. Once it becomes public and you can duplicate the ownership with yourself, there's no reason for us to hold it. I'm going to let Vicki answer the question about the operational group.
First, I'd like to say thanks to our current Permian unconventional team that's gotten us to where we are today, because currently we're running seven horizontal rigs. We expect to ramp that up to 16 next year. We're now getting more aggressive with our properties in the Permian because we now understand them a little bit better. This exploitation team is going to be one that we have developed to get us into a position where we're more entrepreneurial and much more aggressive in the way that we attack our unconventional opportunities in the Permian. This group we expect to start helping us to more accelerate those opportunities that would've been 2 to 3 years out in our typical development schedules.
This team also will focus on ensuring that we provide the technical support to the business unit to make sure that we're spacing our wells correctly, that we're adequately drilling our horizontal wells in the correct direction and spacing. The bottom line is we just expect this to be a technical support to help us to get more aggressive.
Great. Thanks a lot.
Your next question comes from the line of Ed Westlake with Credit Suisse.
Yes. Good morning, Steve.
Morning.
There's a statement in your slides on slide 35 saying, "Expect to complete strategic review in the coming months." Is that a statement just around the overall thinking about the business, or is that around the timing that you might expect for making some of the disposals in the Midcontinent and valorization in the Mid East that you've discussed?
A decision about California.
Right. Okay.
That's intended to be as soon as we have clarity about the proceeds.
Right. Okay.
It's very disruptive, I don't know if people don't understand it. We put out the announcement so that we could go do the work because you can't go secretly go sell 9% of your assets. Once that's done, we'll look at the next step of what we need to do. You can't just disrupt the whole organization all at once with this massive idea without some pretty specific numbers.
A question that maybe you'll be able to answer on the Middle East. Obviously, though, it seems like there's a decent amount of growth still to go for. Thanks for the slides. Is there some sort of recovery factors that you can give on these fields at present to give us some kind of a geological understanding, even if you can't talk about reserve bookings, that could help us think about the long term for these fields, particularly Oman, I guess?
Yeah. Unfortunately, that's part of what you're supposed to keep a secret. They're very high recoveries by U.S. standards or by current U.S. standards. They're like fields that were discovered in the U.S. in the 1930s, not like fields that are discovered last week here.
Okay. The final one, just the chemical cracker. World scale is sort of $5 billion-$7 billion. Is that the right ballpark for you?
No, nowhere near that. This is under $1 billion, our share.
Okay. Great. Thanks very much.
Thank you.
Your next question comes from the line of Leo Mariani with RBC.
Hey, guys, just a question on the Permian here. Just looking at your oil production, it's kind of been flattish there for the last handful of quarters. Clearly, you're accelerating activity in 2014. Talked about an incremental $500 million to drill horizontal, largely unconventional. You guys also talked about clearly significant proceeds coming in the door soon. Ballpark, it's probably easy to get to something like a $10 billion type of number. Should we expect that if you guys have success as we get through 2014, that 2015 and 2016 can see a lot more incremental capital into the Permian, given how big your acreage position is here?
I certainly hope so. If it isn't, then it hasn't been successful. No, we expect the Permian to be self-funding because there's so much cash that comes out of this CO2 business.
Okay. I guess in terms of your activity there, you mentioned that acquisitions didn't seem like they were as paramount. Do you think there's still potential for that down the road if stuff becomes available that looks more attractive to you guys? Do you think you have enough acreage to really drill this aggressively for many years to come?
I don't think we need to do any acquisitions. Obviously, if something attractive comes along, that's different, but we're certainly not going to press acquisitions.
Okay.
We're better off, frankly, buying the shares with the money than doing the acquisitions.
Okay. Thanks a lot. Appreciate it.
Your next question comes from the line of Paul Sankey with Deutsche Bank.
Hi, good morning, everyone. Steve, do you think you can complete the Middle East deal by the end of the year?
Complete? No. You've got to sign a lot of documents, the documents probably fill a room. I expect we'll have clarity as to the proceeds by the end of the year and probably a signing on completion in the first quarter.
When you talk about a minority, I think the previous guidance was 20%, 25% sale. Is that still?
I think you should think of it as being focused on how much money we can bring back in an efficient manner rather than the exact percentage.
Yeah. That's been reported as.
There's some amount of money, which is a sizable number, that we can bring back in an efficient manner. The Middle East business generates a sizable amount of foreign tax credits, we have a pile of those that we can use that would continue to generate foreign tax credits to shelter the income going forward. If you exceed what you have, you pay taxes, U.S. taxes, on money that you would otherwise not pay taxes on. We're mindful of that in this phase.
I understand.
I don't know if that was helpful or confusing.
I think people have been talking about an $8 billion type number as being the ultimate proceeds, you work around the percentage share towards that. I think the year-end guidance that you've given, at least what matters is the number is in line with what we're hoping.
Without going into exact numbers, I don't think that's useful. Again, we're in negotiations. We just did not negotiate with ourselves on the phone.
I understand. The options for California, is that a spin, IPO? What are you thinking there? Thanks.
We really haven't decided what the options are. Generally, simpler is better. Increased complexity is probably not something I'm up for at this point.
Would that imply?
If that's helpful.
Would that imply a spin, then?
What's the simplest thing to do? There's two simple things to do, and only two simple. Everything else requires a lot of brainpower, and I'm short of that right now.
Fair enough. I think I'll leave it there. Thanks, Steve.
Thank you.
Your next question comes from the line of Sven De l Pozzo with IHS.
Yeah, good morning. Seen a big run up in Delaware Basin stocks over recent months. I know you guys have a lot of acreage there. I think it's based on a relatively small number of successes in the horizontal Wolfcamp, such as you had mentioned on your call. I'm wondering, where do you think we stand in making this play more repeatable in the Delaware Basin?
Vicki, do you want to take a shot at that? That's true. There are relatively few wells. We are encouraged by what's going on. We'll let Vicki talk here for a minute.
Again, that's part of what the exploitation teams will be doing, working with our current business unit, and that is to look at the data in the Delaware. We do believe that there's potential there and it is repeatable. One of the things that we're going to focus on trying to do is determine what drives the variations within the reservoir. This team has the skill sets, we believe, to work with the business units to accomplish that. It's just a variability that we want to understand a little bit better. We do believe that that success is repeatable.
In your opinion, is it more upside in the Wolfcamp formation or Bone Springs, or equal, just as an idea? Separately, Wolfcamp in the Midland Basin, how would you compare the two, kind of answering the question the same way, just like you did now?
I think that the upside in both Wolfcamp and the Bone Springs will be ultimately pretty equal. The Wolfcamp in the Midland Basin, certainly we've had some recent success there. Based on the information we see from a couple wells we're drilling now and from offset operators, we're certain that's going to be very successful.
Thank you. Moving over to the Bakken for a moment. Most of your drilling, I think it's been in southwestern Dunn County. Is that to hold the acreage by production or is that just your own choice? Because you've got a lot of acreage outside of that area as well, and I'm just wondering what your plans are for developing that other acreage.
We've been focused on holding it by production.
Okay.
The majority of the drilling was done for that purpose.
Okay, thanks. Pronghorn Member in the Bakken, you mentioned that in your last press release. Have you had any successful wells in the Pronghorn Member? I know that there's offset operators that have had success there. I'm wondering when you guys plan to drill Pronghorn Member or if you have already.
Bill can answer that.
Yeah, we've drilled a couple of Pronghorn wells, we've been very pleased with the success that we've seen so far. I think you could expect more of that.
Okay. Finally, just little bit of data points. If you could help me with the Dolphin project equity income. I know you've disclosed that in the past, it was a while back, just to bring me up to speed on what that is on an annualized basis, if that equity income number, if it's a pre-tax number or a post-tax number. You can get me that later if you want, or if you know it, I'd appreciate it.
Roughly 60% of the income in the midstream business is split between Dolphin midstream pipeline and the Plains interest. If you take our midstream income for a year, I wouldn't use any quarter numbers. For a year, about 60% comes from those two. It's maybe not quite equally divided, but something like that.
Okay. Thank you very much.
Your next question comes from the line of Faisel Khan, Citigroup.
Good morning.
Morning.
Morning. On the $2 billion of annual free cash flow you expect to generate out of the MENA portfolio after the Al Hosn startup, can you discuss if that free cash flow number sort of assumes that you continue to spend capital on growth projects? If you can also discuss if the CapEx number embedded in that free cash flow number, if that's enough to replace reserves?
The answer is we continue to spend it on growth projects, and it would be enough to replace reserves.
It includes some of the projects you're looking at in the UAE and in Oman.
It includes projects that are in hand now that we see we have. If we went and did something brand new, that may have a different effect. If you look at what we have in hand and projects in Qatar and Oman and Abu Dhabi, that includes all of that. If you said, well, we're going to have some projects some other place that's radically different, then it would make a different outcome. This includes enough to replace production.
Okay. Understood. Your comments on the sort of favorable permitting environment in California, is that a result of the legislation that was signed into law by Jerry Brown, or is there something else that's going on in terms of how you're lining up the permitting process in the state?
Vicki can answer that, I think.
Yeah. I would say that the Division of Oil, Gas, and Geothermal Resources for the state of California has been trying diligently to ensure that there's more certainty around the permitting process. They've been processing permit applications as quickly as they can. Granted, it still takes a while in the state because of their personnel resources. Recently, we've also been trying to anticipate the application of details from Senate Bill 4 that was just passed, we're trying to ensure that we stay ahead of the anticipated specific requirements of that bill to ensure that we're not negatively impacted by that.
The Senate Bill, does it help provide more transparency to the process, or does it make the permitting process more difficult?
It will provide more transparency, but it will also require more monitoring from the operator standpoint, also more reporting. We're hoping that the requirements are not so stringent that they overload the staff at DOGGR. That's the bigger issue for us is that increased permitting requirements is going to be a load on their staff.
Okay. Thanks for the color. Just last question from me. Could you give us the sort of what you envision the capital cost being for the ethylene plant, the gross cost?
Well, I said that half of it would be under $1 billion.
Okay.
Whether it's 750 or 800 or something like that's sort of the range.
Okay.
For half of it.
Do you have all the permits in hand, the air permits and the CO2 permits?
Yeah, I think we're about set to go.
Okay, great. I appreciate the time. Thank you.
We'll be spending some money this year, but it'll build up in 2014, 2015, and 2016.
Okay, understood. Thank you for the time.
Thanks.
We do have time for one more question. Your final question comes from the line of John Herrlin with Societe Generale.
Hi, two quick ones. Given more of an unconventional focus, should we expect to see your PUD count go up in the U.S., Steve? PUDs as a percentage of proven.
I understand.
Okay.
The actual PUD count is very large. They're always very reluctant to book PUDs. You've got to put a gun to their head to get them to book PUDs. I would suggest that the PUDs are likely not to change very much as a percentage. It doesn't mean there aren't PUDs. Let me just tell you why. They feel they're borrowing from next year's program. If they book a PUD, they book the barrels now, and the money gets spent, say, next year. They're afraid of hurting their F&D costs next year. Basically, you have this steady state of PUDs and PDP adds, and therefore your F&D costs are, from the perspective of people who do it, more predictable. We can argue, and I have with them, that there's more PUDs out there, they tend to take a very conservative view of it.
I don't think there's any question about that. Not the end of the world. There are worse things you could do.
Okay, that's fine. I just was wondering whether you were going to be more like your peers because you are more conservative.
No. I think it required brain surgery, and we're not up for that as part of my lack of abilities as I get older.
Okay. No lobotomies or PUDing. Next question. With California, you're spending more on G&A, and you said you're going to do more unconventionally. Are you going to be outside existing areas for your unconventional activities? What I'm trying to get at is, in terms of volume recoupment, will production activities be more protracted if you're not within your existing field areas? TBD, to be determined.
I think we're going to build out from our field areas rather than go off. Part of building efficiency is to build out from your existing infrastructure. One of the keys for the next year or so is to keep the efficiency strong. We'll build out from where we are.
Okay, great. Thank you.
Thank you. Chris?
Please give us a call if you have any questions, further questions here in New York, and thanks for joining us today.
Thank you.