Earnings Call: Q2 2014

Jul 31, 2014

Good morning, and welcome to the Occidental Petroleum Corporation's Second Quarter Earnings Conference Call. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Mr. Chris Degner. Mr. Degner, please go ahead. Thank you, Ed. Good morning, everyone, and thank you for participating in Occidental Petroleum's 2nd quarter 2014 conference call. On the call with us this morning are Steve Chazen, Oxy's President and Chief Executive Officer Chris Stavros, Chief Financial Officer Vicki Hollub, President Oil and Gas in the Americas Willie Chang, Executive Vice President of Operations and Sandy Lowe, President of our International Oil and Gas Operations. In just a moment, I will turn the call over to our CFO, Chris Stavros, who will review our financial and operating results for the Q2 and also provide some guidance for the current quarter. Our CEO, Steve Chazen will then provide an update on the progress of our strategic initiatives and also some comments on the composition of the remaining Oxy after separation of our California business. Vicki Holla will then provide an update of our activities in the Permian Basin and Willie Chang will conclude the call with an update on Oxy's midstream business. 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 in our filings. Additional information on factors that could cause results to differ is available on the company's most recent Form 10 ks. Our Q2 2014 earnings press release, the Investor Relations supplemental schedules and the conference call presentation slides can be downloaded off our website at www.oxy.com. I'll now turn the call over to Chris Stavros. Chris, please go ahead. Thanks, Chris, and good morning, everyone. Beginning with this quarter, the disclosure and discussion related to our Oil and Gas segment results will be both on a before and after tax basis with the oil and gas results also segregated between our domestic and international producing operations and exploration program. Oxy generated core income of $1,400,000,000 resulting in diluted earnings per share of 1.7 $9 for the Q2 of 2014, an improvement over both the year ago quarter and the Q1 of 2014. For the 4th consecutive quarter, we continued our strong domestic oil production growth with increases coming from both our Permian and California assets. Domestic oil production for the Q2 of 2014 was 278,000 barrels per day, a new quarterly record for Oxy. Excluding the effect of the Hugoton asset sale, domestic oil production increased 21,000 barrels per day from the year ago quarter with our Permian Resources business growing its oil production by 21%. On a sequential quarter over quarter basis, the growth was 8,000 barrels per day or about 3 percent. Oil and Gas core after tax earnings for the Q2 of 2014 were $1,200,000,000 essentially flat with both the Q1 of this year and the Q2 of last year. In the Q2 of 2014, after tax core income for our domestic business was $679,000,000 On a sequential quarter over quarter basis results at our domestic operations were roughly unchanged as improvement from higher oil volumes and realized prices were offset by lower prices for natural gas and NGLs and higher operating expenses mainly as a result of increased downhole maintenance and surface operation costs. International after tax core income was $576,000,000 for the Q2 of 2014 and results improved about 4% sequentially due to a lifting in Libya, which had none in the Q1 and also increased sales volumes in both Oman and Yemen. On a year over year basis, domestic operations improved by $44,000,000 after tax and international operations declined by $65,000,000 as our Latin American results were meaningfully impacted by insurgent activity in Colombia. For the 6 months year over year comparison, domestic operations after tax income was 1 point $4,000,000,000 an increase of almost 13%. In the same 6 month period, international operations core income was $1,100,000,000 a decline of 4%. For the Q2 of this year, total company production volumes excluding the Hugoton production averaged 736,000 BOE per day, an increase of 9,000 BOE in daily production from the Q1 and down 17,000 BOE from the quarter a year ago. Excluding Huguetzen, domestic daily production improved 8,000 BOE from the Q1 of this year with half of the increase coming from the Permian and the remainder from the Williston Basin in California. On a commodity specific basis, our domestic oil production grew by 8,000 barrels per day with 3,000 barrels per day each coming from the Permian and Mid Continent and the remainder from California. Domestic NGL and natural gas production volumes were virtually flat for the quarter. International production increased by 1,000 BOE per day on a sequential quarter over quarter basis. MENA production grew 11,000 BOE per day sequentially, primarily due to the scheduled Q1 plant turnaround at Dolphin, higher production in Oman due to new wells coming online in the northern blocks and in Iraq, which reflected increased cost recovery barrels. These increases were offset by 10,000 barrels per day of lower production in Colombia due to pipeline disruptions from insurgent activity. Our Q2 2014 worldwide realized oil prices of $100.38 per barrel improved slightly compared to the Q1 realizations of $99 a barrel. Our domestic oil price realizations were about 2% higher on a sequential basis despite continued widening differentials in the Permian Basin. Realized prices for our domestic NGL and natural gas production fell 6% and 7% sequentially reflecting declines in benchmark prices. Price changes at current global prices affect our quarterly earnings before income taxes by $37,000,000 for $1 per barrel change in oil prices and $7,000,000 for $1 per barrel change in NGL prices. A swing by of $0.50 per 1,000,000 BTUs in domestic natural gas prices affects quarterly pre tax earnings by $25,000,000 These price change sensitivities include the impact of production sharing contract volume changes on our income. Our oil and gas cash operating costs were $14.68 per barrel in the Q2 of 2014 compared to $14.33 per barrel in the Q1. Domestic operating expenses were higher in the Q2 of this year compared to the Q1 of this year due to higher downhole maintenance and surface operation costs primarily in the Permian Basin. MENA production costs increased in the 2nd quarter due to higher costs related to the Libya lifting, partially offset by lower surface operations costs. Taxes other than on income, which are related directly related to product prices were $2.83 barrel for the Q2 of 2014 and $2.88 for the 1st 6 months of this year and our 2nd quarter exploration expense was 54 $1,000,000 In Chemicals, our 2nd quarter 2014 pre tax earnings of $133,000,000 were slightly lower than the first quarter results of 130 $6,000,000 $144,000,000 in the year ago quarter. The seasonal uptick in demand in construction and agriculture markets in the Q2 were more than offset by routine planned plant outages and unplanned customer outages. We expect our 3rd quarter pre tax earnings to be about $150,000,000 reflecting anticipated increases in sales and production volumes. In midstream, pretax segment earnings were 219,000,000 dollars for the Q2 of this year compared to $170,000,000 in the Q1 of this year and $48,000,000 in the Q2 of last year. The 2014 sequential quarterly improvement in earnings resulted mainly from higher marketing and trading performance, driven by commodity price movements during the period and higher income from the Dolphin Pipeline, which was negatively impacted by plant turnarounds in the Q1 of this year. For the 6 months of 2014, we generated $5,700,000,000 of cash flow from operations before changes in working capital. Working capital changes decreased our cash flow from operations by $100,000,000 to $5,600,000,000 During the 1st 6 months of 2014, cash flow from operations declined approximately $650,000,000 compared to the same period a year ago. The first half of twenty fourteen included a tax payment related to the gain on the sale of the PAGP units and the 1st 6 months of 2013 included a collection of a tax receivable. On a normalized basis, cash flow from operations during both periods would have been similar at roughly $5,800,000,000 Capital expenditures for the 1st 6 months of 2014 were $4,700,000,000 net of partner contributions. In the Q2, we received proceeds of $1,300,000,000 from the sale of our Hugoton assets and spent about $240,000,000 toward domestic bolt on acquisitions. After paying dividends of $1,100,000,000 buying back $1,600,000,000 of our company's stock and other net flows, our cash balance was 2 $400,000,000 at June 30. Our debt to capitalization ratio was 13% at the end of the quarter. Our 2014 annualized return on equity was percent and return on capital employed was around 11%. The worldwide effective tax rate on core income was 40% for the Q2 of 2014 and we expect the combined worldwide tax rate in the Q3 to remain about the same. Lastly, I'll outline some guidance for the Q3. In the domestic business, on April 30, we closed on the sale of our 18,000 BOE per day in the Q1 and 6,000 BOE per day in the second quarter. For the Q3, excluding Hugoton, we expect our domestic oil production to grow between 6,008,000 barrels per day sequentially or roughly 10% on an annualized basis. We would expect this domestic oil production growth rate to accelerate over time. Domestic NGL production should see a modest increase, although this should be somewhat offset or equally offset by lower natural gas production volumes. We expect our total domestic production to grow between 5000 to 7000 BOE per day. For the international at current prices and assuming normalized operations in Colombia, we expect total international production sales volumes to increase by about 10,000 BOE per day from the second quarter levels. Excluding the Hugoton, total company wide production in the 3rd quarter is expected to increase by 15,000 to 17,000 BOE per day sequentially or at an annualized rate of about 8%. We expect Q3 2014 exploration expense to be about $100,000,000 pre tax. I'll now turn the call over to Steve Chase and he'll provide an update on some of our strategic initiatives. Thank you, Chris. We recently announced new executive management teams and responsibilities for both the California Resources Corporation or CRC and Occidental Petroleum. Todd Stevens, the President and CEO of CRC and Bill Albright, Executive Chairman, bring proven leadership abilities and both have played an important part in building and managing our California operations. Mark Smith, the former CFO of Ultra Petroleum was hired as Chief Financial Officer at CRC and brings an extensive background in corporate finance and deep understanding of operations at an independent oil and gas producer. With these appointments, most of the key roles in the organization have been filled and we are confident in their ability to succeed as a stand alone public company. In addition to developments regarding personnel, we continue to make progress in the planned spin off of the California company. During the Q2, we filed the initial Form 10 registration statement and have already responded to the comments received from the SEC. CRC has initiated steps to secure its debt financing, which we expect to be completed in the Q3. We anticipate $6,000,000,000 of proceeds from total funded debt. The cash proceeds from CRC's debt financing will transfer to Occidental as a tax free dividend shortly prior to completion of the spin off, which we expect to occur in the Q4. Upon the spin off of CRC, Occidental retained ownership of approximately 19.9% of CRC for a period lasting up to 18 months. During that period, we intend to conduct an offer to exchange the CRC shares we retain for Occidental shares. The California business continues to perform well and is executing on its oil and gas production growth strategy. The Q2 of 2014 oil production grew 10% compared to the Q2 of last year. The business generated approximately $1,200,000,000 of cash flow from operations during the 1st 6 months of 2014. We expect to see our C. R. C. Management team present a more detailed view of the business and its growth strategy to investors as it commences its roadshow in the Q4. At Occidental Petroleum, each of the 7 members of the new executive team have made significant contributions to the company. Their individual strengths and combined leadership will shape the future of Oxy as we embark on a new chapter in the company's history. Following the execution of CRC spin off, Oxy's philosophy of disciplined capital allocation and living within its cash flow will continue. Oxy's core businesses will be focused on delivering moderate volume growth, generating higher earnings and cash flow per share and leading to improved financial returns. After completion of the strategic initiatives we laid out last fall, our area of focus will consist of a significant and leading position in the Permian Basin. Our Permian Resources unit will represent the key area of oil growth within our domestic business with annual production growth expected to easily exceed 20% per year over the next several years as we accelerate our horizontal drilling program. We also expect margins in the Permian to improve as we focus on additional drilling efficiencies, reducing our well costs and further enhancing our oil price realizations. Vicki Hollub will provide a further update on the Permian Resources business shortly. Our Permian Basin operations will be rounded out other domestic oil and gas operations in South Texas, our 24.5% interest in Dolphin project and a smaller and improved business in the rest of Middle East North America, our operations in Colombia as well as our midstream operations in the Chemical business. Each of these businesses identified opportunities to drive earnings and cash flow growth and also support our ability to grow our dividends for our shareholders. Operations without profitable growth will see minimal capital spending or will be disposed of. After several years of significant capital investment, 2 significant projects are nearing their completion. As Willie Chang will describe in more detail shortly, we expect the BridgeTex pipeline to start up later this quarter, provide us with an advantage to access to the Gulf Coast for our Permian crude oil production. We also expect the start up of the El Hosen gas project in the Q4. Assuming similar product prices, these two key projects combined with growing oil volumes from the Fermium Resources Development Program should provide us with a meaningful earnings and cash flow per share growth into 2015. Finally, as a part of our strategic initiatives, we will continue to focus on raising cash from our lower growth and lower margin assets. In the Middle East, we continue to make progress on negotiations with our partners and we will reduce our exposure to the region. Our growth our goal here is to improve the business' ability to grow profitably. Over time, we expect to achieve a similar balance in our asset mix with at least 60% of our oil and gas production coming from the United States. We are continuing to explore strategic alternatives for our assets in the Ponce and Williston Basin. We expect to monetize our remaining interest in the general partner of Plains All American, which is valued at approximately $4,500,000,000 as well as possibly some other midstream assets when market conditions warrant. Since the end of the Q3 of 2013, we have repurchased more than 26,000,000 shares of the company's stock for roughly $2,500,000,000 and approximately 20,500,000 shares remain available under current share repurchase authorization. We expect that we will be able to further reduce our share count by roughly 60,000,000 shares through the cash dividend from the CRC separation and by about 25,000,000 shares from monetization of our remaining interest in the Plains pipeline. Coupled with the 20,500,000 shares in our current repurchase program, we should be able to reduce our total share count by more than 100,000,000 shares or about 13% of the current outstanding shares. Most of the share repurchase ability will occur after the spin off of CRC. These amounts do not include the ability to repurchase additional shares through proceeds received from the sale of a portion of our interest in the Middle East, share reduction from an exchange of our remaining interest in CRC or the monetization of other assets. We expect Oxy's remaining businesses to deliver moderate volume growth result of the expanded Permian Resource Development Program and shift towards horizontal drilling, the start up of the Elhosin Gas Project and our participation in several other attractive international growth projects. These identified an intermediate growth opportunities in projects capable of more than replacing the production from the spin off of CRC by the end of 2015. And Oxy's shareholders will still retain the value created from the spin off as owners of CRC shares. We expect to generate higher financial returns going forward as a result of our investment investment strategic initiatives, our improved capital efficiency and operating cost structure, start up of operations for BridgeTex, the Elhos and Gas Project along the separation of our California business provide a natural uplift to our return on capital employed. Return on capital employed was 12 point 2% in 2013 and we expect it to rise to around 15% as we exit 2015. Now I'll turn the call over to Vicki Hollub for an update on our activities in Permian Resources. Thank you, Steve. This morning, I'd like to continue the discussion of our Permian Resources business. In the Q2, Permian Resources produced an average of 72,000 barrels of oil equivalent per day, which is an increase of over 7% from last quarter. This is 28% on an annualized basis. We produced 40,000 barrels of oil per day for the 2nd quarter. This is a 21% increase from a year ago and an 8% increase from last quarter. During the Q2, our capital expenditures were 490,000,000 dollars We averaged 24 operated rigs, of which 17 were horizontal and we drilled 87 wells, including 42 horizontals. Year to date, we have drilled a total of 67 horizontal wells of which 43 have been completed and put on production. 38 wells are currently waiting on completion or hookup. In the Q3, we plan to drill 54 horizontal wells and place an additional 54 wells on production. I'll first discuss how our Permian Resources teams are well positioned to deliver long term growth and then I'll review that base knowledge, we have been and are continuing to make significant investment to assess the rock and fluid properties in our unconventional reservoirs across our acreage. This is helping us to develop a better under the geologic parameters that drive productivity such as porosity, saturation, brittleness, total organic content, mineral and geochemical composition, rock and fluid compatibility, fracture distribution and stress regimes. Our Permian Resources and exploitation teams are applying this appraisal work to construct calibrated petrophysical models to characterize prospective benches and target landing zones within each bench. As a result of our work to date, we have now identified over 7,000 drilling locations across our 2,000,000 net prospective acres. This is an increase of more than 2,500 since the beginning of this year. We expect to continue to grow the number of locations through our successful exploitation efforts. We're also conducting an extensive appraisal of high potential benches to optimize our well designs and development plans. This appraisal work includes collection and analysis of whole cores, cuttings, advanced log suites, microseismic surveys and 3 d seismic surveys. We are leveraging our learnings from participation in more than 450 outside operated wells along with data from some of the existing 4,400 outside operated wells in which we have a working interest. Based on our findings, we're testing various field development and well design alternatives including optimization of well spacing, lateral length and cluster spacing. Additionally, we have also increased proppant concentrations and are evaluating various frac fluids. Our results are exceeding expectations indicating that we are quickly moving toward optimal design for the Wolfcamp A and B benches in the Midland Basin and the Delaware Basin. For example, at South Curtis Ranch in the Midland Basin, we completed and put on production 6 wells, which had average initial rates of 850 BOE per day versus prior initial rates of 750. Our recent South Curtis Ranch 2,00818 well achieved a peak rate of approximately 1100 BOE per day on gas lift. At Barilla Draw in the Delaware Basin, our recent Eagle State 20 eightfive well achieved peak production of 16 20 BOE per day and a 30 day average production of 11 20 BOE per day, significantly higher than our average 30 day production of 8.30 of prior wells in the Wolfcamp A and B benches. With respect to supply services and logistics, we have secured key resources to efficiently accelerate fulfilled development and production growth. We have ordered long lead time equipment and secured favorable material and service contracts by leveraging our position across our Permian Resources and EOR businesses. These contracts ensure the availability productive resources at competitive cost in strategic areas such as drilling rigs, simulation, tubing, casing, cementing, directional drilling and artificial lift. We have contracts or options in place to expand our fit for purpose drilling rig fleet to 54 rigs in 20 16. We have expanded our completion capacity to 4 24 hour frac crews and plan to further expand the fleet as we accelerate development. On the efficiency front, we intensified our efforts to improve operational execution and compress cycle time. In early 2014, we implemented a batch drilling program to accelerate and improve the cycle time on our horizontal wells. In our batch drilling program, we drilled a vertical section of the well with a smaller fit for purpose drilling rig. And following the vertical section, we used a higher capacity directional drilling rig with specialized services to complete the more complex curve and lateral sections of the well. This approach has allowed Permian Resources to transition our existing lower cost vertical rigs into our horizontal development programs to improve our overall cost structure. This method enhances the utilization of specialized services to achieve reliability and improve cost. We have reduced drilling costs in South Curtis Ranch by 24% since the end of last year. Now for a quick update of our water management strategy. The Barilla Draw system has been pressured up and is operational. To date, we have completed 6 fracs including 1 zipper frac using this new system. We are achieving a cost savings of $2.50 per barrel of water. In the Midland Basin, we are duplicating this effort by installing a water distribution system at West Merchant with delivery rates up to 90,000 barrels per day. The system will fully operational by September and we expect similar cost savings from this investment. These two systems are the first phases of our comprehensive water management strategy, which we will discuss in more detail in future calls. I would now like to share a few more details of our activity in each of our geographic areas. In the Texas Delaware specifically in the Brilla Draw area in Reeves County, I'm pleased to report that in the Q2, we drilled 10 horizontal wells and completed 7 wells whose initial production rates for the Wolfcamp A and B matched the 11.50 BOE per day achieved in the Q1. In the area highlighted on the map where we hold over 35,000 net surface acres, we will drill an additional 27 horizontal wells in the second half of twenty fourteen. We continue to increase efficiency and expect our average well cost of $8,500,000 to improve an additional 5% by the end of this year. We are encouraged by our success in this appraisal program. As a result, we are transitioning into an accelerated development phase in Barilla Draw. In the Midland Basin, where we hold approximately 90,000 net surface acres, we are continuing our appraisal and development drilling efforts. We drilled 14 horizontal wells in the 2nd quarter and placed 21 horizontal wells on production. We will drill an additional 55 horizontal wells in the second half of twenty 14. Our average drill time for the horizontals is 27 days per well with total drilling and completion cost averaging $7,000,000 per well. With the knowledge gained, we are transitioning from appraisal to accelerated development in our merchant field. As a result of the strong performance this year, we are increasing our 2014 production growth expectation to between 15% 18% from the previous 13% to 15%. In addition, we are increasing Permian Resources capital by $200,000,000 to 1,900,000,000 dollars The total number of wells drilled will remain roughly the same with a greater percentage of horizontal wells. The resulting production increase from the incremental capital will primarily impact 2015. In closing, our 2014 program is designed to delineate and appraise our acreage in order to maximize both ultimate recovery and financial returns. We're on track to exceed expectations in 2014 and we have the required resources and infrastructure in place to meet our 2016 production target of more than 120,000 BOE per day. In addition, Oxy has several exciting midstream projects related to our Permian infrastructure and takeaway capacity that is a unique competitive advantage. I will now turn the call over to Willie to discuss in more detail. Thanks, Vicki. Good morning, everyone. I'd like to give you a very quick overview of our Midstream and Marketing segment and describe how it literally connects our oil and gas production and then spend the majority of my time to share our strategies to support the Permian Basin growth that you just heard about from Vicki. We strongly believe that having multiple perspectives in house, those of a large Permian producer, a significant midstream infrastructure operator and a crude NGL and gas marketer gives us a very unique advantage that differentiates us from others. The midstream operations not only enables us to unlock and preserve value for our core business, it also allows us to utilize our assets to move 3rd party volumes to market. Further, we have the scale to drive key strategies in the Permian Basin. First, let me provide a quick overview of our Midstream Marketing segment. The role of the Midstream Group is to maximize realized value for Oxy production by ensuring access to markets, optimizing existing assets and building out key assets across the value chain. This is increasingly important with the U. S. Moving to an abundance of resource and a significant shifting of global supply and demand. Our Oxy owned domestic mystery mass as shown on slide 33. These are supplemented with contracted capacity on 3rd party assets, all of which allow us to market substantially all of Oxy's domestic oil, NGLs and gas production, comprised of roughly 470 BOE per day, 270 8,000 barrels a day of crude, 72,000 barrels a day of NGL and over 700,000,000 cubic feet a day of gas. We also market 3rd party crude and NGL volumes focusing on parties whose supply is located near our transportation and storage assets. These 3rd party volumes are significant and add in excess 200,000 barrels a day for 3rd party crude and NGL volumes. This aggregation of volume both serves a need for producers and end users and allows us to better utilize and optimize our assets. We also have gas processing plants, CO2 fields and facilities. We process equity in 3rd party domestic wet gas to extract NGLs and other gas byproducts including CO2 and deliver dry gas to pipelines. We produce approximately half of our CO2 requirements. Currently, we operate 1800 megawatts of power generation. The majority of these power plants are located next to our OxyChem and oil and gas facilities in order for us to share infrastructure, act as a steam host and to consume power with the remaining power sold to the power grid. Now let me go back to our key Permian Basin assets where our midstream operations are focused on providing access to multiple markets for our Permian production. Our equity production is roughly 150,000 barrels a day and is expected to grow significantly. Additionally, we purchased and market over 200,000 barrels a day of third party crude production. Turning to slide 34. Centurion is a large gathering and mainline system in the Permian that we continue to optimize and significantly expand. Our Centurion system has roughly 2,900 miles of pipeline, over 100 truck stations, 6,000,000 barrels of storage and has access to most third party transportation assets that enable us to deliver crude to all Permian refineries as well as to the origin point of key pipelines taking production out of the Permian Basin. We're focusing on 2 new key takeaway points: Colorado City, which is the origin of our BridgeTex pipeline, which we're jointly developing with Magellan and the Midland South exit, which is the origin to 3rd party pipelines Longhorn and Cactus. When at full capacity BridgeTex and Cactus will add an additional 500,000 barrels a day of takeaway capacity from the Permian Basin. These new pipelines give us access to the Houston and Corpus, Refining Centers and to our own Ingleside terminal in Corpus Christi. It also supplements our existing access to Cushing. We're working on options to handle the growing light crude production in the Delaware Basin and Southeast New Mexico in order to preserve the Permian crude qualities in the Midland Basin. Currently Oxy and Magellan are in the final phases of construction on the Bridge Tex pipeline, which is expected to start up later this quarter. The 4 50 mile pipeline will be capable of transporting 300,000 barrels a day of crude between the Permian region and Gulf Coast refinery markets. Oxy has a significant committed takeaway capacity on BridgeTex as well as other third party pipelines exiting from the basin. When all planned pipelines are in operation by mid-twenty 15, our midstream unit will have access to long term cost advantaged takeaway capacity. As a major producer in the Permian Basin, we've been a driving force behind the construction of new infrastructure adding transportation capacity from the basin in order to benefit Permian production and avoid production constraints. Now I want to highlight how important adequate takeaway capacity is to market value. On slide 35, I've shown Midland WTI pricing compared to Cushing WTI and the U. S. Gulf Coast LLS markets for the period of 2,009 through today. You can see how the differentials were transportation parity in a market with adequate takeaway capacity. Now note the differentials in the widening significantly as the supply and demand balance tightened in a takeaway constrained market. We've seen Midland LLS differentials as wide as $30 a barrel in January 2012 January 2013 during the winter refinery maintenance periods. This year we've seen wide differentials throughout the entire year as increases in production have further tightened the supply and demand balance. The Midland LLS discount this year has averaged just over $10 a barrel versus just under $6 a barrel during the second half of twenty thirteen. With the upcoming completion of BridgeTex and the start up of Cactus Pipeline by mid-twenty 15, expect differentials to return to levels that reflect incremental cost of transportation between the Permian and Cushing or the Gulf Coast. As you heard in Vicki's comments, Oxy's production growth will be significant in West Texas and Southeast New Mexico. With our long term capacity on multiple pipelines, we will have security of placement with takeaway capacity of roughly 3 times our current equity production from the Permian Basin. We'll also have access to key markets to protect our Permian crude premiums. Let me give you an update on our Ingleside Energy Center in Corpus Christi. This is the formal naval station that we purchased in late 20 12, which is located outside of the congested ship channel near the mouth of Corpus Christi Bay. We're developing a terminal facility that will be able to handle up to 100,000 barrels a day of propane and 200,000 to 300,000 barrels a day of condensate and crude. The site will contain 2000000 to 4000000 barrels of storage and also provides flexibility to accommodate future processing facility options on-site or at a nearby OxyChem complex. We sanctioned both projects and expect the LPG propane terminal to be complete mid-twenty 15 and the first phase of the crude condensate terminal will be completed in the first half of twenty sixteen. Our midstream business has demonstrated steady earnings growth over the last few years. Slide 37 shows the premium or the value add from our Permian Crude Logistics and our marketing business. This is in terms of dollars per barrel on equity production adjusted. This is versus a group of 6 Permian producers based on the available public information we're able to pull. You can see we've added approximately $1.50 a barrel better than the group average. On the same basis, we expect to capture an additional $2 plus of value once the BridgeTex and Cactus pipeline start up as a result of our long term advantaged takeaway capacity. This reinforces the importance of key infrastructure. If these new pipelines were not sanctioned, the entire basin would suffer continued significant discounts to market due to the infrastructure complaints constraints. You can see the reasons we've moved forward on these key pipeline initiatives. I hope this gives you a better view of our midstream business and in particular its key role in supporting our domestic oil and gas business. This is an exciting time for our midstream business as we continue to build out a strong platform for future opportunities. Thanks for your attention. I'll turn the call back now to Chris Degner. Thank you, Willie. Operator, we'll now poll for questions. Thank you. We will now begin the question and answer session. And our first question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead. Thanks. Good morning, everyone. Thanks for all the additional color in the Permian. Steve or Vicki, I don't know who wants to take this. If I could have one question on the Permian and then one on the restructuring process please. Specific to the Permian, my understanding is that when we look at the publicly available information, your well results have been area. And my understanding is there some kind of reporting issue with you guys. I wonder if you could share something with that. And as it relates to the wells that you have drilled per the presentation today, can you isolate where in the Permian you're drilling in terms of which horizon? What are these averages that you feel you've derisked multiple sections across your acreage? Just a little bit more color as to what your confidence level is and the repeatability of these kind of results across the 2,000 plus locations? And I've got a follow-up please. Yes, Doug. Some of the issues have been associated with at what point in the flowback and production process of the well do we take the test. And some of our teams have been turning in 24 hour completion initial completion rates to the Railroad Commission in the state of Texas that are not when the well is fully cleaned up and not necessarily at its peak. With that said, I'm going to just be honest with you that in some areas, we still are lagging behind our competitors in terms of our initial rates and production. And that's why we've been aggressively here recently trying to try new things with respect to our frac designs to improve our performance. In the Midland Basin South Curtis Ranch, we are getting better and we're testing not only frac designs in terms of fluids and profit volumes, rates and things like that, all of which are helping us to improve. But we are we have discovered that our cluster spacing was not optimum for the initial fracs that we've done there. So we're confident that going forward our South Curtis Ranch performance is going to improve. Now certainly the best area that we have right now is our Wolfcamp production in the Texas Delaware. That's where we're doing best and we're actually outperforming some of our competitors in the Texas Delaware. So we're confident that there we've gotten closer to figuring out the right completion technology and the right not only profit concentrations, sand total volumes and rates, but also the design of the total job. So in the Texas Delaware, we've actually increased our proppant volumes by about 20 percent and our fluid injection volumes by about 50%. We've also increased our rate there. So we expect continuing good performance and maybe even better performance there. And in fact, it's in the Texas Delaware where we've added most of the 2,500 D well locations that we've added since the beginning of the year. So while in Texas, Delaware, we feel like we're doing a great job. We know still could improve it. We see opportunities for that. South Curtis Ranch in the Midland Basin, we've changed some things and we expect to see better results here coming pretty soon. On the risking Vicki of the locations on multiple benches or horizons I should say? Yes. Most of our about right now about 45% of the 7,000 wells are in the Wolfcamp. And as you know, we probably as an industry know more about the Wolfcamp than any other. About 20% of our inventory right now is in the Bone Spring in Southeast New Mexico. Those wells as you know are also doing pretty good. Where we're seeing in Texas, Delaware, we're seeing payout time periods of 1.5 years or less. And in Southeast New Mexico, we're starting to see some good performance there in the Bone Spring. So I'd say that right now 65% of our inventory is probably minimal risk in terms of economics and the ability to profitably grow it. The others are in benches that we still have some work to do. Thank you. And Steve, my follow-up hopefully quickly is the Middle Eastern process, you have a pretty material contract expiring in Oman next year. And obviously, things are kind of moving on this year in terms of absence of news flow on the disposal process. My understanding is you may have things may be moving a little quicker than perhaps you've been prepared to say previously. I just wonder, if you could give us an update on your confidence level on maybe getting the 3rd if you could give us an update on your confidence level on maybe getting the 3 separate transactions completed over the next let's say 12 months? Yes. I think one of the transactions is moving along very well. And I think we'll get to resolution here in the easily foreseeable future. There is the contract extension in Oman, which will have to be part and parcel of whatever goes on there because otherwise it expires in 2015. So I think they take a little longer, but pretty confident there. The third one is I think more challenging and we'll see what can be done there. But there are some issues that are not related to us that I hope work their way out, but I think that's probably into next year. All right. I'll let someone else jump. Thanks very much. Thank you. Thank you. Our next question comes from Leo Mariani of RBC. Please go ahead. Hey guys, you referred a little bit to some other projects where you may be able to grow international production outside of Al Hosn. Is that kind of part and parcel with your MINI's negotiations? Could you guys just elaborate on that a little bit? I think there's 2 parts there. We have some new contracts in Colombia for heavy oil, which I think we're pretty enthused about. And I think those are pretty much there. So I think those will be they're away from some of the areas where we've had political difficulties if you want to call them that. So I think those are I think in pretty good shape. And then obviously we're principally one of the principal objectives of the program is either large scale reductions in areas where there's no growth or smaller reductions in areas where there's growth in partnership with the local government. So I think some of the growth will come out of the partnership with the local government in those areas where there's potential for that. Okay. That's helpful. And I guess just in the Permian you guys clearly have a dramatic acceleration of the rig count over the next couple of years here. Just trying to get a sense of how much of that may be secured at this time by contract? And what are you kind of seeing there in terms of service costs? We're definitely going to be able to get up to at least 54 rigs in by 2016. That's our current plan is to go to 45. However, we can we have the options in place to go to 54. So that's not really at risk for us right now. We know we can achieve it on the drilling rig side. And the reason we have that range there, we've got 47 in our plan for 2016. And the reason on the slide that the 7 additional are grade, we have the option to get them, so we know we can. What we'll be doing between now and 2016 is trying to ensure that all the rest of the support services in the Permian are available and that we can secure that to get to the 54. We feel like we've already secured the services support services outside the drilling rig that can support 47. It's just a matter of can we get the 54 and we're working on that plan now. Surface cost, we're still trying to manage that. Cost in the basin are going up as demand increases, but we're trying to leverage our size to minimize the increases that we're seeing. Yes. There's also productivity gains from this too. So I think we're we've saved this so far. We saved about 10% from last year's cost already. That's not driven primarily by reducing the day rate, but by drilling more wells per day essentially. So I think the productivity gain should more than offset whatever modest inflation there is in the cost. Okay. That's helpful for sure. And could you guys just elaborate on other assets that you might be thinking about disposing of? You guys made a comment that said that anything that's not profitable could be up for sale. Any more color you have around any of those processes? I think we've said that I reiterated this morning that we're still looking at options for the Piazza and the Williston Basin, maybe a little more activity in one of those we don't know yet. And we also said that buried in the comments was that if we can get the right arrangement perhaps some of the midstream assets where we retain the contract, so we can continue to move our crude and get the margins from the trading, but perhaps dispose of the underlying asset and let somebody else take the tariff. Okay. Thanks. It's helpful. Our next question comes from Ryan Todd of Deutsche Bank. Please go ahead. Great. Thanks. If I could ask maybe a little bit more on the Delaware Basin. I appreciate all the detail. Can you talk a little bit about your use of long laterals? I mean have you drilled 2 mile laterals? Or are you extending the lateral length? And if so, how much of your acreage there in the basin do you think would be conducive to longer laterals? Currently in the Delaware Basin, we're drilling lateral lengths of between 3,300 and 4,200 feet. What we're doing right now is some modeling with respect to the optimum lateral lengths in the basin. As you know, the Wolfcamp productivity in the Texas Delaware is much better than in the Midland Basin. And thus far, we're seeing some good productivities from the lateral lengths that we're drilling. We haven't really drilled much yet over 4,200 feet. 2 of the challenges there are, as I said, at what point do you have you drilled so much that you start destroying value in terms of the just the friction effects of the longer laterals? And the other thing is that you have the challenges of the acreage positions with respect to ensuring that you've set up your opportunities to go with the longer laterals. But currently, we're seeing that probably it's more likely to need the longer laterals in the Midland Basin rather than in the Texas Delaware. However, with that said, we are trying a lot of things. We haven't gotten to that point yet. We're trying to minimize the variations that we have per stage of evaluation to ensure that we understand what impact each thing that we change is having on our productivity. I mean, maybe a little different focus than some other people. I think we focus on our sort of our finding cost sort of calculation rather than the IP calculation. So from our perspective to lengthen the laterals may cost us more money. You might get more IP, but maybe at a cost of a higher finding cost. And we're just that's not the way we think about things. Some a small producer may be more interested in IPs. Okay. That's helpful. And have you seen I guess still in the Delaware, have you seen what are you seeing from an oil gas mix in your Wolfcamp wells there? And are you seeing much variation across the extent of your acreage? We're seeing a little bit of variation, but typically we're seeing anywhere from 72% to 80% oil in the Texas Delaware. And in most cases, we're seeing above 75%. We're a little pickier, I mean, we have better acreage than some other people who are doing a fair amount and get gassier results. Okay. You can see that our oil is rising in our gases and if you look at the numbers we've given you. So we're basically a little pickier than some other people who are maybe that's all I got. So they're drilling gassier wells. Okay. No, that's helpful. And on the pace, the outlook in terms of obviously your ramp is pretty significant over the next few years. Is the pace of development there broadly going to be governed by your view of the entire logistical system and how much capital you can put into the basin without destroying returns? Or what's going to be the primary, I guess, governing factors on the potential to maybe even show upside over that 3 year window? We think on the production numbers we've given, we have considerable upside just with the drilling we're showing. But putting that aside, it's a return based business and we just assume learn let other people make mistakes and learn from that before we expand our footprint a lot. But there's also other logistical issues in the basin. We want to make sure that we have takeaway capacity for the oil. I'm more concerned frankly about takeaway capacity for gas. You're not going to be able to flare the gas. And the gas production in the basin is likely to grow sharply in the next year or 2 as people drill these gassier wells. And so you could wind up with a bad situation. So our one of our major focuses is to make sure that we have gas takeaway capacity so that we don't drill wells we have to have shut in because clearly you're not going to be able to flare. All right. Well, thanks. I appreciate the help. I'll leave it there. Thank you. Our next question comes from Jason Gammel of Jefferies. Please go ahead. Yeah. Thanks. Maybe I'll take another stab at this Permian drilling situation more in terms of managing the drilling inventory. And I'm just going to use some very simplistic numbers At the current rig count and the number of wells that you drilled the last quarter, you'd have about a 20 year inventory, doubling the rig count. We'll take that back to a 10 year inventory. But I also assume you're probably going to be adding locations over time. So how do you actually then balance the amount of drilling inventory that you have from an NPV basis? And what I'm really getting at more broadly, do you see divestiture opportunities within the Permian Basin as well as potential acquisitions? Yes. If I look at the list of mistakes I've made over the last 20 years, the mistake I've made most is divesting anything in the Permian Basin. And because there's so many horizons, there's so much there, there's so much oil available in the system. So we didn't divest that much, but I regret every acre. So I think that while I'm here, we're not going to be divesting anything. I do think that I think the program that Vicki has outlined is sort of the minimum program. That's what we think we could achieve over the next couple of years without wasting money. As we get better at this and the basin matures, there'll be more opportunities because we're sort of everywhere. And I think that I think we could accelerate the program further. This is what we're talking about now. As the basin matures, we find more stuff to do. The results maybe turn a little better. I think we'll go ahead. I am concerned about infrastructure constraints over the next 2 or 3 years. While we have as Willy pointed out lots of oil takeaway capacity, a lot better positioned than most people I think. And so I think we're in pretty good shape for that. And we do control the gathering system, so we can gather our own stuff. But I am all concerned about gas. And so we're probably going to take steps to make the gas more certain. I think that's probably more my gating concern is the crowding in the costs. Great. That's pretty clear. If I could ask just one more on the CRC spin out process. It looks to me and maybe I've just missed something, but I think that your estimate on amount of shares that you'll be able to repurchase from the transaction has went to $60,000,000 from a range of $40,000,000 to $50,000,000 And my question is, is this going to be related to the just under 20% retention of equity and the exchange over time? And do you still expect to take a $5,000,000,000 dividend out? No. Dividend is $6,000,000,000 Okay. And so we haven't counted the shares in the exchange. So it's simply we had we got our modelers out and so they divided $6,000,000,000 by $100 to come up with the 60,000,000 shares. We didn't pay a lot for that advice. Very good. I think I understand now. Okay. Thank you. Our next question comes from Paul Sankey of Wolfe Research. Please go ahead. Hi, everyone and congratulations to those who have new roles. Actually, I kind of didn't understand Steve that last point, believe it or not. The exchange offer has to be completed within 18 months and any proceeds from that I guess is the word would be used for buyback additional buyback? No. It's actually just so you understand the shares the 19.9% shares that we own Oxy shares in other words put us add in the paper it says anybody who wants to can get CRC shares and they give us back Oxy shares for it, okay? We can do that without paying any tax. In theory, if we had that kind of debt around, we'd exchange it for debt, but there that kind of much debt around to do that. If we do anything and the 3rd alternative would be simply to distribute the shares to the shareholders. If we couldn't do that. That also would be tax free. If we sold it for money, we would have to pay tax on it. So our preference would be to do the exchange offer. So basically, you put it's a split off of the 19.9% in terms. So I think those are so what we did was we sort of guessed it how much it might we haven't included that number in our 60,000,000 shares, but there'll be some number of shares that we'll exchange the CRC shares for Oxy shares and we do that without paying any tax. Okay. And the follow on slide which is 21 where you show the same as $60,000,000 says clearly that you don't include anything from MENA. I was just wondering why it says it did not reflect debt reduction. Does that mean you're going to pay down debt as well? Well, there's a small amount of debt reduction probably. Okay. So it's just in the rounding. Yes. I figured I just wanted to confirm that. So the fact that your list of mistakes just made me think of Lindsay Lohan actually funny enough, but there you go. Would that involve you potentially making an acquisition in the Permian further acquisitions of scale? Thanks. The answer to the Permian acquisition of scale is no. You have to speak to the next round of management about that, but I sure wouldn't do that. The prices are ridiculous far above. We trade it 6, 7 times whatever you want to say of cash flow and the acquisitions are very dilutive and I can't imagine doing one. I suppose if there's a collapse in oil price or something like that that would be a different story. But absent a huge reduction in the public market values of these companies, I can't even imagine doing one. And I don't imagine that hopefully my successors are well trained enough not to do anything stupid too. Yes. And then finally for me thank you. And then finally for me, in the past you sort of openly debated the buyback as the benefits and merits of the buyback. Is there some sort of price sensitivity to this? Or is this going to be a fairly blind process? And I'll leave it there. No. Hopefully, it won't be a stupid process. I think that's what you're blind is and I guess another word for stupid. So I think Well, I think you said in the past that there's a fair value that you believe in. There's a fair value we believe in and we'll do what we yes, we're going to buy back the shares ultimately, but it also depends on the price. We would expect that during the process of divesting of the California company, the stock will during the confusion will trade at the Oxy stock will trade at some what we would view as a discounted value. And we would expect that a lot of we could buy a lot of shares during that period. I'd be pleased to be wrong, but that would be a reasonable expectation during that period. I guess what I was driving at partly as well as the potential for you to spend more money organically to grow faster as opposed to buyback? More but not materially more, I think is the answer. Could you put another $1,000,000,000 to work? Yes. Could you put $2,000,000,000 to work? Maybe. Could you put $3,000,000,000 to work? No. I think we got a plan that we could execute efficiently. We could probably do a little better as things progress. So I think the answer is yes, we could do that, but not for very long. Thanks very much, Steve. Thanks. Our next call our next question comes from Ed Westlake of Credit Suisse. Please go ahead. Yeah. Yeah. One question on the Permian, Vicki. Just obviously you've broken out current vertical and horizontal and then you've explained how doing the 2 activities separately makes sense. As you look at that rig count chart, I mean, can or should we assume you're still going to have the same sort of ratio? Or maybe help us understand how many vertical rigs are going to be in that 47 plus 7? I don't see us having more than about 6 or 7 vertical rigs at any given time in the future. So the bulk of the 47 to 54 that we'll have only I would expect only about 6 or 7 of those to be vertical. Right. And obviously you've given us the 7,000 locations and Jason was probing on that. But as you ramp up the rigs your inventory is going to drop I think perhaps a little bit faster. So at least on a forward looking basis when we get to 2016, which is obviously a bit further in the future. Where would you then go next after the initial inventory? It seems like you've got some good sweet spots in the Midland and fantastic sweet spot in the Texas Delaware. It feels like a lot of your acreage is over in the Bone Springs. And so to maybe talk about what how the returns would change as you shifted those rigs around through the program? Yes. Let me say that that 7,000 is based on the appraisal work and the evaluations that we have done to date, we fully expect that 7,000 to grow. As you know, we have a huge acreage position. And what we're trying to do is go through our initial step of exploration and then appraisal before we're adding some appraisal work has to be done before we add locations to our current inventory. So I'm almost thinking with what we're seeing, I wouldn't be surprised to see that our inventory increases by the amount of wells that we drill. So I expect that inventory to grow fairly significantly over the next couple of years. And I expect it to grow mostly in the Texas Delaware Southeast New Mexico, although we still haven't done a lot with some of the areas within the Midland Basin. What we're trying to do is stay very focused on limiting the our focus areas, so that we can make sure that we accelerate efficiently. And then we're also limiting our appraisal areas too to make sure that we go in, we get our appraisal work done and then we transition to development mode. So some appraisal work there are some areas where we haven't even begun our appraisal work. And then just a question on the midstream. I mean, I know you sort of signaled you're going to be selling the Plains All American GP. Well, it seems like it's time to build another one given the amount of midstream assets that you are still building. So I mean, would you think about creating a new Oxy MLP down the road to help fund the infrastructure that will be required for you and for others in the Permian? I think that you got to split the revenue streams that come out of this into 2. 1 is the tariff streams. And those are once you build the pipeline, they're sort of not very interesting. And the other is sort of the trading or streams our ability to move the oil to different spots. We would just assume retain the contracted volume streams and ultimately dispose of the tariff streams, if you will. So I think as far as building another line, I think we've got plenty for us. We're 3 times what we currently produce. So we got plenty for us. We'll see how it goes. Again, I'm focused about putting the midstream money right now in the moving gas to make sure that's not an issue. When you run an MLP or any kind of midstream business, you're thinking about $1 or $0.50 a barrel. When we look at a barrel of oil, we're thinking about 100 And so our view is we need to make sure that our $100 oil gets moved and worry a little less about the $0.50 fee. So we're focused on making sure that the base by building this stuff out, we made it better for everybody in the basin. And then on the gas, we expect to do the start to start to get traded independently of the company's loan? And maybe just a reminder of where your royalty position is in some of your legacy acreage? Yes. It's a complicated number to put it mildly. First of all, the king of this royalty stuff is in the California business. So you probably can ask them about it when they show up. But putting that aside, we there's royalties, let's say, under one of our EOR fields that we own the royalty interest there or a large piece of the royalty interest. So if we were dispose of that in some way that would hurt our finding costs and that our margins would shrink, our present worth would shrink that may not make and that and our reserves will go down because your economic limit is reached sooner. On the other hand, we have a fair amount of production where we just get checks from 3rd parties. And we don't really know the number at this point. It's not they're counting the checks, I think, just trying to figure it out. But for the excluding California, the royalty income is somewhere in the range of $300,000,000 a year and I'll find some way and we just have to go root through it and figure it out. I think where it doesn't affect our ability to manage our base business because our royalties are scattered in a number of places. Somebody would like to pay 15 times cash flow. I think we're game. On the other hand, where it affects our base business, we just assume keep it because I think it will hurt us in our finding costs going forward. Thanks. Very clear and helpful. Thank you. Thanks. Our last question comes from John Kirlin of Societe Generale. Please go ahead. Close enough. The operator is not French obviously. Yes. Thanks, Steve. In the Permian, how much of your drilling activity is pad based at this stage? Vicki? Because of the early stage that we're in with respect to our drilling, we're not doing a lot of pad drilling at this point, but the pad drilling will come. It's already built into the development plan. What we're doing is appraisal work and we expect to be very heavily in the pad drilling in 2015. Which will also help. And as you know we do a lot of pad drilling elsewhere. So it's not like we're opposed to it, but we're in the process of drilling the appraisal parts of some of these programs. And we will definitely go to not only pad drilling, but manufacturing mode once we get beyond the appraisal stages. Permian, do you think you have enough people? We're the ramp in the Permian, do you think you have enough people? We're adding people. We're ramping up and we are going to have to add a few more people to our Permian Resources and Exploitation teams and our field execution teams. But so far we've been able to add the people that we need as we progress. Okay, great. Last one for me Steve. You talked about addressing the midstream. Does this mean MLP or just outright sale? Well, I mean it doesn't if you could if somebody will give you an MLP multiple in all cash, I think that's for us probably a better option. On the other hand, if you can't do it that way and we get it some other way, I think we could do an MLP. Great. Thank you. Thanks. This concludes our question and answer session. I would like to turn the conference back over to Mr. Degner for any closing remarks. Hi. Thank you everyone for listening. I know it's been a busy day for you all. We'll be available in New York for your questions. Thanks. Thanks. The conference has now concluded. Thank you for attending today's presentation.