ex99_2-20140130.htm

	—	We grew our domestic oil production by 11,000 barrels per day over 2012 to 266,000 per day;
	—	We exceeded our capital efficiency goals, reducing our drilling costs by 24 percent from the 2012 level;
	—	We reduced domestic operating costs by 17 percent;
	—	We added about 470 million barrels of reserves achieving an overall replacement ratio of 169 percent;
	—	Our total costs incurred associated with those reserve adds were about $7.7 billion, resulting in an apparent finding and development cost of under $17;
	—	We increased our return on capital employed from 10.3 percent in 2012 to 12.2 percent in 2013.

As a result of our development program, we improved our capital efficiency by 24 percent domestically over 2012, which translates to about a $900 million reduction in capital for the wells drilled in 2013. Of this improvement, 50 percent came from the Permian Basin, 25 percent from California and 25 percent from the rest of the domestic assets. We accomplished these improvements while successfully completing our program by drilling approximately what we had planned. We also reduced our domestic operating costs by 17 percent, or by about $470 million compared to 2012. About 48 percent of this improvement was in the Permian Basin, 46 percent was in California and the remainder was in the other domestic assets. While we focused on these efficiencies, we also grew our domestic oil production by 11,000 barrels per day.

With respect to reserves, we had a very successful year in growing the Company’s reserve base by adding substantially more reserves than we produced, over 90 percent of which was added through our organic development program. We ended the year, based on a preliminary estimate, with about 3.5 billion barrels of reserves, which represents an all-time high for the company.

Our total company reserve replacement ratio from all categories, before dispositions, was about 169 percent, or about 470 million barrels of new reserves, compared with 278 million barrels we produced during the year. In the United States, our reserve replacement ratio was 190 percent. The replacement ratios of the California properties and the Permian non-CO2 properties were similar to the overall company ratio. Our reserves replacement ratio for liquids from all categories was 195 percent for the total

Over the past several years, we have built a large portfolio of growth oriented assets in the U.S. In 2013, we spent a much larger portion of our investment dollars on the development of this portfolio. Our organic reserve replacement for the year reflects the positive results of the development efforts capitalizing on the large portfolio built over the years. Our 2013 development program, excluding acquisitions, replaced about 168 percent of our domestic production with about 291 million barrels of reserve adds. In addition, we transferred 115 million barrels of proved undeveloped reserves to the proved developed category domestically as a result of the 2013 development program. Our 2013 acquisitions were at a multi-year low of $550 million providing reserve adds of 32 million barrels.

At year end, we estimate that 73 percent of our total proved reserves were liquids, increasing from 72 percent in 2012. Of the total reserves, about 70 percent were proved developed reserves, compared to 73 percent in 2012. The increase in the share of the proved undeveloped reserves compared to last year was the result of the reserves added for the Al Hosn Gas Project. We expect to move these reserves to the proved developed category at the end of this year once initial production starts in the fourth quarter.

2013. This is consistent with our expectations that the DD&A rate of growth should flatten out as recent investments come online and finding and development costs come down. The success of our organic reserve additions and the efficiencies we have achieved in our operations demonstrates the significant progress we have made in turning the Company into a competitive domestic producer. One of our long-term goals domestically has been to achieve a 50 percent pretax margin after finding and development and cash operating costs to generate solid returns. We believe we are achieving that now and expect to continue to do so going forward.

Consistent with what we have said repeatedly, our focus in 2013 was to enhance shareholder value through our results. For this purpose, our program was heavily focused on growing our domestic oil production, improving our capital efficiency and our finding and development costs and lowering our operating costs. We met or exceeded all of these goals and as a result, we increased our return on capital employed to 12.2 percent, a significant improvement from the 10.3 percent level in 2012 and a testament to the hard work and dedication of all of our employees. We expect to see further improvements in our returns in coming years as a result of recent investments.

development plans and production growth. An additional $0.1 billion will be spent in these and other domestic assets for facilities projects that were deferred from 2013. The domestic oil and gas capital program will continue to focus on growing oil production and the entire increase in capital will go to oil projects in California and the Permian business units. We also expect to continue to fund growth opportunities in our key international assets, mainly in Oman and Qatar, and complete the Al Hosn Gas Project. Our 2014 capital for Oman and Qatar will increase by about $0.3 billion over 2013. Our exploration capital will increase by about $0.1 billion, in part due to deferred spending from 2013. Our midstream capital will increase by about $0.1 billion as a result of spending on the BridgeTex pipeline and two new terminals at Ingleside and our chemical capital will increase $0.1 billion due to the Mexichem joint venture we announced last year, while we complete the New Johnsonville chlor-alkali facility. Our success in improving our capital efficiency and operating cost structure has provided us with the ability to expand our development opportunities that meet our financial return targets. The capital program and production growth that I outlined reflects the benefit of our streamlined structure and our commitment to continue to fuel growth by exploiting our large portfolio primarily in California and the Permian basin.

With respect to our 2014 production, we expect our companywide production volumes to grow to between 780,000 and 790,000 barrels per day compared to 763,000 barrels per day in 2013, with a fourth quarter exit rate of over 800,000 barrels per day, excluding the planned Al Hosn production. This increase will come almost entirely from domestic oil production while we expect to see a continued modest drop in our domestic gas volumes. Our domestic oil production is expected to grow from 266,000 barrels per day in

While the elements of the 2014 program that I discussed assumes no changes to the Company structure or its mix of assets, we do expect the Company to look significantly different by the end of the year. The strategic review we are undertaking will result in significant changes to the Company’s asset mix. Our capital program, production expectations and other elements of the 2014 program will be adjusted as related transactions are concluded.

	—	The Al Hosn Gas Project is expected to start its initial production in the fourth quarter and start contributing to our cash flow;
	—	We expect the BridgeTex pipeline to come online around the third quarter and start contributing to our Midstream earnings and cash flow;
	—	The New Johnsonville chlor-alkali plant is expected to come online early in the year and will make a positive contribution to the operations of our chemical business.

With respect to the initiatives outlined in the first phase of the Company’s strategic review announced last year, we completed the sale of a portion of the Company’s investment in the General Partner of Plains All American Pipeline in October, resulting in pre-tax proceeds of about $1.4 billion. After this sale, we continue to hold about a 25 percent interest in the Plains General Partner, which at current market prices would be valued at about $4 billion.

We have made steady progress on our discussions with key partners in the countries where we operate in the MENA region for the sale of a minority interest in our operations there. Due to the scale and the complexities of a potential transaction, we expect these discussions to continue through the first half of this year. We have also made good progress in our pursuit of strategic alternatives for select Midcontinent assets. We expect to provide further information on any transactions as they conclude around the end of the second quarter and will announce material developments as they occur.

Many of the steps we have taken in 2013, including our success in improving our efficiency and the actions that our Board has authorized, lay the groundwork for stronger results for this year and beyond. The operational improvements we expect to achieve in 2014, coupled with the strategic actions we expect to execute this year, should place the Company in a position to improve its returns while continuing to grow and increase its dividends to maximize shareholder value.

This morning I will review two of our largest domestic operations, our Permian and California businesses, describing our 2014 plans as well as longer-term growth opportunities. In 2013 we implemented an important transition plan in both of these businesses, and the success we achieved built a solid foundation for long-term growth.

	—	Continue the development of our large anchor projects in each of our operating areas, which will enable us to allocate a significant portion of our capital to projects with solid returns, low execution risk and long term growth.
	—	Further reduce our drilling and completion costs to improve our finding and development costs and our project economics.

We manage our Permian Basin operations through two business units, the Permian EOR business, which combines CO2 and waterfloods, and the Permian Resources business, which is where our growth oriented unconventional opportunities are managed. I will refer to the CO2 and waterflood business as Permian EOR and the other business as Permian Resources. The Permian Basin designation will be for the combined operations. In the Permian Basin we spent over $1.7 billion of capital in 2013 with 64% focused on our Permian Resources assets. In 2014, we plan to spend just under $2.2 billion overall in the Basin. The entire $450 million increase will be spent on our Permian Resources assets, representing approximately 70% of our total capital spend in the Basin. We expect the Permian EOR business to offset its decline in 2014 and actually grow 1.4%. The Permian Resources oil production is expected to grow faster in a range of 20% to 25% and its total production by 13% to 16%. On a combined basis for the Permian Basin, this should translate to oil production growth of over 6% in 2014 and total overall production growth of over 5% while generating $1.8 billion of cash flow after capital.

drilling program. We drilled 49 horizontal wells with 47 completed and producing. The combination of improvements in well costs, our own results and those of neighboring operators have given us the confidence to dramatically shift our program to more horizontal drilling in 2014. Our Permian Resources team will average running about 21 rigs of which 17 will be drilling horizontal wells. We plan to drill approximately 345 total wells, about 50% of which will be horizontal. This compares to 330 total wells drilled in 2013 where only 15% were horizontal.

We have two main goals for our Permian Resources business in 2014. First, we intend to continue the evaluation of the potential across our full acreage position. Second, we plan to pilot various development strategies, including optimal lateral length, frac design and well spacing both laterally and vertically. We believe this will position us for accelerated development as we exit 2014 and go into 2015.

We believe we have one of the most promising and underexploited unconventional portfolios in the Basin. In 2013, we added 200 thousand net prospective acres to our unconventional portfolios, and now have about 1.9 million prospective acres. This is a prime position in the Permian Basin. Our acreage in the Midland Basin, Texas Delaware Basin and New Mexico give us exposure to all unconventional plays, which is unique. This will give us flexibility to develop our most attractive opportunities first, and to mitigate risks. Based on the work we have done to date, we have identified approximately 4,500 drilling locations across our portfolio, representing 1.2 billion net barrels of resource potential. We believe we have made conservative assumptions regarding prospective acres, well spacing and expected ultimate recoveries and expect these numbers will grow as we learn more. We see the largest near-term growth in the Midland Basin, which

We believe our measured approach to our unconventional portfolio has worked to our advantage. Our Permian Resources production comes from approximately 9,500 gross wells, of which 54% are operated by other producers. On a net basis, we have approximately 4,400 wells of which only 15% are non-operated. This has given us the opportunity to observe the results achieved by other operators in the Basin, learn from those results and optimize our approach to maximize the opportunities on our acreage. The success of our capital and operating cost efficiency efforts in 2013, has also enabled us to significantly improve our cost structure which has increased our opportunity set. For example, a typical well in the Collie area that had IRR of 24% before our capital and operating cost reductions, now yields IRR of 48% using the same product prices. We achieved similar success in all of our most active areas across the business unit. Finally we have established a multi-step methodical process for our unconventional acreage in the Permian Resources business that includes (i) exploration to establish the presence of a commercial resource; (ii) testing and data gathering to optimize well and completion design; (iii) pilot programs to assess variability of well performance to design full field development plans; and (iv) transition to manufacturing mode for full field development. This process is helping us to prudently develop our acreage, maximizing cash flow and returns. As a result, we are now prepared to accelerate our activities in our Permian Resources business where we believe the opportunity in front of us is one of the biggest in the Basin.

We have been most active with our horizontal activity to date in the Midland Basin where we have drilled 16 wells. In 2014, we plan to spend approximately $790 million to drill 147 wells including 74 horizontal wells. We expect to average 8 rigs in this area during the year. Our largest opportunity here is in the Wolfcamp Shale where we have tested Wolfcamp A and B benches and plan to target our activity to test the remaining benches.

One of our most successful pilot projects in this basin is South Curtis Ranch, which has now gone into full field development mode. This is a property that we acquired in 2010. We have drilled 63 vertical and 6 horizontal wells to date and plan to drill over 200 additional horizontal wells on this acreage. Results thus far have been as expected with initial thirty-day production rates for the horizontal wells averaging approximately 800 boepd.

average 5 rigs during the year. Our horizontal activity will be focused in the Wolfcamp where we believe the A, B and C benches will prove to be the most prospective. We drilled or participated in 3 horizontal Wolfcamp wells in 2013 and will increase that to 45 in 2014. Our activity is centered in Reeves County where we historically have drilled vertical Wolfbone wells. Early horizontal results are proving to have better economics, but there are some plays where vertical development is still more efficient. In our Collie area, we plan to drill 43 vertical wells targeting the Bell and Cherry Canyon formations. This represents a continuation of the one rig program we executed in 2013.

In New Mexico, we plan to spend approximately $370 million to drill 97 wells including 50 horizontal wells. We expect to average 4 rigs during the year. The Bone Spring formation in New Mexico is the second largest opportunity in our portfolio behind the Wolfcamp Shale. In 2013, we drilled 16 horizontal wells testing the 1st, 2nd and 3rd Bone Spring sand intervals. Our results were very encouraging, and we expect to increase the program to drill 30 horizontal Bone Spring sand wells in 2014.

Of the $2.2 billion to be spent in the Permian Basin in 2014, $660 million will be allocated to our Permian EOR business. As I previously mentioned, this business unit is a combination of CO2 and water floods. It is symbiotic to manage these assets together as they have similar development characteristics and ongoing monitoring and maintenance requirements. The last couple of years we have actually spent more capital on waterfloods as we mature the next CO2 developments. In 2014, 25% of the $660 million will be spent on current waterflood development and the remainder on CO2 floods. Further, we have 1.4 billion net barrels oil equivalent in reserves and potential resources remaining to be developed in the Permian EOR

Over the last several years the focus of our Permian exploration program has been to identify unconventional opportunities, which are then transitioned to full field development through the evaluation process I explained earlier. Our approach has been very successful giving us a large opportunity set that we are now working to fully develop. We continue to see the addition of new plays in the Basin and see years of exploration drilling opportunities ahead in our 2 million prospective acre position.

Now that I have gone through some of the specifics of our program for the Permian Basin, I will explain our overall business strategy. We are approaching our development program with a multi pronged strategy that (i) maximizes the field resource potential; (ii) controls costs to optimize returns; and (iii) gives us a strategic advantage to improve our realizations. We are using targeted horizontal and vertical drilling as appropriate, optimizing development and completion plans from lateral length to frac efficiency as well as lift strategies to maximize recovery. We are making heavier infrastructure investments like power, water handling and gas processing to pre-plan for life of field success. These strategies, coupled with our successful exploration program, accomplish the first of these objectives. We

will continue to manage costs and take advantage of our progress along the learning curve with leading technologies and execution efficiencies, to accomplish the second. We are also investing in additional take-away capacity, including the completion of the BridgeTex pipeline and build out of our gathering systems, which will give our crude a strategic advantage to reach either the Houston Ship Channel or Corpus Christi markets.

Finally, I would like to comment on our plans for the Permian Basin over the next several years. With the combined businesses, we have more than 2.5 billion barrels of oil equivalent in reserves and potential resources. Within each business unit we have the flexibility to shift capital among projects within that business, as well as the flexibility to shift capital between the two businesses as needed. Our large and diverse portfolio creates opportunities for a variety of growth options. In the Permian Resources business, at our current pace, we believe we have over 15 years of development and growth opportunities. Given that the Permian EOR business is generating significant cash flow and we expect our opportunity set to continue to grow, we plan to double our rigs over the next three years to accelerate the development of the Permian Resources unit’s growth opportunities. We expect this to result in the doubling of our Resources unit’s production from approximately 64 mboepd in 2013 to more than 120 mboepd in 2016. In Permian EOR while it is large with a somewhat slower growth curve, we have significant opportunities going forward with continued positive cash flow to fuel the growth of the Resources unit. Combined with the EOR growth opportunities, we expect to grow our overall Permian Basin production by roughly a 10% compounded annual growth rate through 2016.

Now I will shift to California. In 2013, we spent $1.5 billion of capital. Our main goals were to deliver a predictable outcome, advance low-risk projects that contribute to long-term growth, reduce the cost structure, lower our base decline, create a more balanced portfolio and test exploration and development concepts. We achieved every one of these objectives. We produced 154 mboepd and generated $1.3 billion of free cash flow after capital. We progressed the development of our steam floods in Kern Front and Lost Hills, and started the redevelopment of our Huntington Beach Field. We improved our capital efficiency by 20% versus 2012 and also reduced operating costs by $4.70 per BOE, or 20%.

Overall in 2014, we intend to continue the capital strategy shift initiated last year, which was to focus the majority of our capital on low decline projects. Our goals for this year are to accelerate the rate of production growth and maintain our lower cost structure. We will also continue to advance several low-risk, high-return long-term growth projects and capitalize on our exploration successes. In 2014, we plan to spend $1.9 billion of capital, of which approximately 40% will be spent on water floods, 20% on steam floods and 40% on unconventional and other developing plays.

We expect to average about 27 rigs in California in 2014, compared to an average of 20 rigs in 2013. We plan to drill around 1,050 wells in 2014 compared to 770 in 2013. We expect this program to deliver around 11% oil production growth, or over 4% total production growth, while generating $1.0 billion of free cash flow after capital at current prices. We believe the rate of growth will further accelerate in 2015 and beyond as a number of the steam and water flood projects reach full production and the base decline is

Let me now share some of the highlights of the program for this year, beginning with the water floods. In the LA Basin, we plan to spend $500 million in the Wilmington and Huntington Beach Fields. Our Wilmington Field development in 2013 exceeded expectations. We drilled 135 wells and will increase that 7% to 145 wells in 2014. Our horizontal program was particularly strong, and horizontal wells will represent an even greater percentage of wells in 2014.

Our Heavy Oil business unit was a key focus area in 2013 and will be again in 2014. We plan to spend $350 million to drill about 420 wells, compared to 324 wells in 2013. We’ll also continue the multi-year development of the Kern Front and Lost Hills steam floods and pilot new projects. I would also like to highlight that the business achieved record production in the fourth quarter, producing 19,000 boepd, an increase of 4,000 boepd from the first quarter of 2013.

At Elk Hills, our key objective is to lower the high decline rate and we have made significant progress toward this goal. In 2014, we plan to spend $600 million in capital to drill 325 wells, which is an increase of $170 million over 2013. About 55% of Elk Hills capital will be targeting our shale reservoirs where our capital efficiency efforts in 2013 had a significant impact. We experienced an average of 23% decline in well costs for these

programs and 21% decline in operating costs, which dramatically improved the economics and increased the opportunity set. For example, a typical well that generated 30% IRR prior to our efficiency initiatives now delivers 50% IRR using the same product prices. In 2014, we will drill around 130 shale wells at Elk Hills, an increase from 80 in 2013. The remaining Elk Hills capital will target continued development in the shallow oil zone and Stevens sands.

Our California Exploration program has delivered solid results for over 5 years. The 2014 California program will continue to explore both unconventional and conventional targets. The unconventional program targets several prospects similar to the 2013 discovery. The conventional program will target prospects in and around our existing production in both the San Joaquin Valley and Ventura County. Our extensive proprietary 3D seismic surveys are yielding an exciting inventory of leads and prospects, which will provide years of drilling opportunities.

Lastly, I would like to give you some perspectives on our development plans over the next several years in California. We expect to continue the capital strategy we initiated in 2013, the shift to lower decline and lower risk steam and water flood projects. We believe we can grow our California production from 154 mboepd currently to 190 mboepd in 2016, or roughly a 7.5% compound annual growth rate. Our steam and water flood projects will contribute 80% of that growth. In fact, 90% will come from projects that are already online. We think this positions California as one of the lowest risk growth profiles in the industry. Further, we are targeting

primarily oil drilling, which will make our portfolio more oily, contributing to solid margin expansion going forward. We expect to grow our oil volumes by roughly a 15% compound annual growth rate through 2016. Over the long-term, we expect our California growth prospects to benefit from changes in our asset mix. Elk Hills and THUMS, while having the potential for years of continued production, have lower growth prospects due to the mature state of both of those fields. On the other hand, our water and steam floods, as well as unconventional opportunities, should continue to give us double digit growth for years to come. The share of our production from Elk Hills and THUMS has shrunk from 64% in 2009 to 44% in 2013. This shift will continue going forward and the larger share of higher growth projects will further accelerate the growth rate in coming years.

As in the Permian Basin, we are continuing to test new ideas to further improve our drilling, completion and development efficiency in all of our projects. We are also working diligently to comply with the new regulatory requirements created as a result of the passage of Senate Bill 4 in California. We have a dedicated team addressing the associated issues and currently we don’t expect significant delays in our development plans.

As you can see, while the Permian Basin and California stories are different, they are both very exciting. The hard work and dedication of our people have put both of these assets in a position for continued success and 2014 is the year both of these businesses will begin to accelerate their growth as we have completed the transition to a focused growth oriented development program and are set for long-term growth.

I will begin with several highlights from the quarter and the year. In the quarter, we produced 270,000 barrels of oil domestically, which resulted in second half growth of 7,000 barrels per day over the first half average, in line with our previous guidance and setting a new company record. We continue to be the largest oil producer onshore in the U.S. Total company production was 750,000 BOE per day, impacted by severe weather and plant turnarounds domestically and continued regional disruptions internationally. We exceeded the goals we set for the year for operating costs and capital efficiency. Our oil and gas operating costs were $13.76 for the twelve months of 2013, an improvement of over 8 percent from the 2012 total year rate. Domestic capital efficiency savings were 24 percent, exceeding our goal of 15 percent. We had core earnings of $1.4 billion or $1.72 per diluted share for the fourth quarter and $5.6 billion or $6.95 per diluted share for the twelve months of 2013. For the twelve months of 2013, we generated $12.3 billion of cash flow from operations before changes in working capital, we

Turning to earnings more specifically, core income was approximately $1.4 billion or $1.72 per diluted share. Compared to the third quarter of 2013, the current quarter results reflected lower oil and gas core earnings driven primarily by lower realized oil prices, seasonally lower earnings in the Chemical segment and reduced core performance in the midstream segment driven by lower margins in the marketing and trading businesses, largely due to commodity price movements.

Now, I will discuss the segment performance for the oil and gas business. Oil and gas core earnings for the fourth quarter of 2013 were $2.1 billion, a decrease from both the third quarter of 2013 and the fourth quarter of 2012. On a sequential quarter-over-quarter basis, the decline in earnings resulted primarily from lower domestic oil prices, partially offset by higher oil prices in MENA. Our sales volumes improved as we recouped the underlifting to date in Iraq, although unrest in Colombia delayed a lifting until the first quarter. Operating costs mainly in the Middle East/North Africa increased with the increased volume lifted in Iraq.

Total production for the quarter was 750,000 barrels per day, representing decreases of 17,000 barrels from the third quarter and 29,000 barrels from the year ago quarter. On a sequential quarterly basis, these results reflect domestic growth in California offset by severe weather interruptions in the Permian and Midcontinent regions and the conclusion of the final plant turnarounds in the Permian. The severe weather caused significant damage to infrastructure and logistics capability that has continued to somewhat impact production in January. We expect a return to normal operations with no effect on production in February. MENA

production was lower primarily due to contract effects in Oman and field and port strikes in Libya. In addition, insurgent activity in Colombia negatively impacted production by about 3,000 barrels per day. On a year-over-year basis, full cost recovery and other adjustments under our production sharing and similar contracts, reduced total company production by 12,000 barrels per day.

Our domestic production was 470,000 barrels per day, a decrease of 6,000 barrels per day from the third quarter of 2013 and 5,000 barrels per day from the fourth quarter of 2012. While we experienced a number of unanticipated impacts this quarter, we are very pleased with how our oil-directed capital program finished the year. We grew oil production 3,000 barrels from the third quarter, driven mainly by California. We achieved our previous guidance even with the impact of the severe winter weather. For the twelve months of 2013, our domestic oil production has increased by 11,000 barrels per day or 4 percent versus 2012. This growth will accelerate in 2014. NGL production decreased 6,000 barrels per day in the fourth quarter versus the third quarter, almost entirely in the Permian, resulting primarily from the final plant turnarounds which were concluded in November and third-party facility disruptions. Natural gas volumes were lower by about 19 mmcf per day compared with the third quarter, with nearly the entire decline coming from the Midcontinent area.

Turning to realized prices, compared with the third quarter, our worldwide crude oil realized price decreased about 4 ½ percent, primarily reflecting changes in benchmark prices. We experienced improvement in NGL pricing domestically which contributed to a 10 percent increase in worldwide NGL realized prices, while domestic natural gas realized prices experienced a 2 percent increase driven by improvement in the benchmark.

Oil and gas production costs were $14.13 per barrel in the fourth quarter and $13.76 for the twelve months of 2013, compared to $14.99 per barrel for the full year of 2012. Domestic operating expenses remained about flat from the third quarter of 2013. International production costs increased in the fourth quarter due to higher liftings in Iraq, which have high operating costs.

Turning to Chemical segment core earnings, fourth quarter earnings of $128 million were $53 million lower than the third quarter, primarily driven by lower caustic soda and PVC pricing and seasonal factors. We expect first quarter 2014 earnings to be $100 million. Lower caustic soda pricing and higher energy and ethylene costs going into the year are the primary drivers for the decrease in segment earnings versus the fourth quarter of 2013.

Midstream segment earnings, which were $68 million for the fourth quarter of 2013, compared to $212 million in the third quarter of 2013 and $75 million in the fourth quarter of 2012. The 2013 sequential quarterly decline in earnings resulted mainly from lower marketing and trading performance, driven by commodity price movements during the quarter, and lower margins in our power generation and gas processing businesses which were negatively impacted by the plant turnarounds in the fourth quarter.

In the twelve months of 2013, we generated $12.3 billion of cash flow from operations before changes in working capital. Working capital changes increased our cash flow from operations by $600 million to $12.9 billion. Capital expenditures for the full year of 2013 were $8.8 billion, of which $2.4 billion was spent in the fourth quarter. We generated approximately $1.4 billion of cash from the fourth quarter sale of a portion of the Company’s interest in the General Partner of Plains All-American Pipeline and $270 million of cash from the sale of a Chemical investment earlier in the year and used $645 million for acquisitions of domestic oil and gas assets. After paying dividends of $1.6 billion, buying back $945 million of Company stock, retiring debt of nearly $700 million and other net flows, our cash balance was $3.4 billion at December 31. Our debt-to-capitalization ratio declined to 14 percent at year-end from 16 percent at year-end 2012. Our 2013 return on equity was 14 percent and return on capital employed was around 12 percent.

spent on long-term projects in 2014. We expect that about 20% of our total capital expenditures will be on projects that will make significant contribution to earnings and cash flow in future years. Although with the start-up of Al Hosn, BridgeTex and New Johnsonville this year, this proportion should reduce meaningfully next year.

—	Domestic oil and gas development capital will be about 49 percent of our total capital program.
		○	We expect to average about 61 operated rigs versus 50 in 2013. The increase will be driven primarily by increased spending in California. In the Permian, our rig count will increase only slightly as we swap horizontal rigs for vertical rigs.
		○	Our total domestic oil and gas capital is expected to increase by about $800 million. Permian and California should each increase about $400 million on a year-over-year basis. The Midcontinent will remain flat at around $900 million.
		○	Our capital will continue to be directed to oil projects, and this will be the biggest driver of growth in 2014.
—	Internationally;
		○	Our total Al Hosn gas project capital should decline about 20 percent from the 2013 levels, and will make up about 7 percent of our total capital program for the year.
		○	Qatar capital spending is expected to increase about $200 million for the North Dome Phase V development plan.
—	Exploration capital spending should increase about 35 percent from the 2013 spending levels and represent about 6 percent of the total

		capital program. The focus of the program domestically will be in the Permian basin and California, with additional international drilling in Bahrain and Oman.
	—	The U.S. Midstream capital will increase about $200 million to approximately $700 million as we spend to complete the BridgeTex pipeline project, which is scheduled to be operational in the second-half of 2014, and to begin construction of an LPG export terminal and crude terminal at Ingleside.
	—	Chemical segment capital will be about $500 million, which includes the Ingleside Ethylene cracker scheduled to begin construction in the third quarter of 2014.

Overall, we expect production to be between 780,000 and 790,000 BOE per day in 2014. Domestically, we expect oil production for all of 2014 to grow to a range of 280,000 to 295,000 BOE per day, or approximately 9%. We expect NGL volumes to be relatively flat with 2013 levels, and continued modest natural gas production declines resulting from limited drilling. Production in the first quarter should be about flat to the fourth quarter and should grow fairly evenly through the year as activity builds and we execute our program.

Occidental Petroleum Corporation
Return on Capital Employed (ROCE)
For the Twelve Months Ended December 31,
Reconciliation to Generally Accepted Accounting Principles (GAAP)


	2012		2013
RETURN ON CAPITAL EMPLOYED (%)	10.3%		12.2%



GAAP measure - net income	4,598		5,903
Interest expense	117		110
Tax effect of interest expense	(41	)	(39	)
Earnings before tax-effected interest expense	4,674		5,974

GAAP stockholders' equity	40,048		43,372
Debt	7,623		6,939
Total capital employed	47,671		50,311

	—	Continue to optimize operating costs without affecting production to improve our current earnings and free cash flow.
	—	Build on our successful exploration efforts in each of our core areas.
	—	Evaluate data and test various new concepts in our pilot areas, which will set up the anchor projects of the future.