Good morning, and welcome to the Occidental Petroleum Corporation second quarter earnings conference call. All participants will be in listen only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. 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 second 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, Willy Cheng, 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 second quarter 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 the separation of our California business.
Vicki Hollub will then provide an update of our activities in the Permian Basin, and Willy Cheng 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 and our filings. Additional information on factors that could cause results to differ is available in the company's most recent Form 10-K. Our second quarter 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 $1.4 billion, resulting in diluted earnings per share of $1.79 for the second quarter of 2014, an improvement over both the year ago quarter and the first quarter of 2014. For the fourth 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 second quarter 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%. Oil and gas core after-tax earnings for the second quarter 2014 were $1.2 billion, essentially flat with both the first quarter of this year and the second quarter of last year. In the second quarter of 2014, after-tax core income for our domestic business was $679 million. 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 million for the second quarter of 2014. Results improved about 4% sequentially due to a lifting in Libya, which had none in the first quarter, and also increased sales volumes in both Oman and Yemen. On a year-over-year basis, domestic operations improved by $44 million after tax, and international operations declined by $65 million, as our Latin American results were meaningfully impacted by insurgent activity in Colombia. For the six months year-over-year comparison, domestic operations after-tax income was $1.4 billion, an increase of almost 13%. In the same six-month period, international operations core income was $1.1 billion, a decline of 4%. For the second quarter 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 first quarter, and down 17,000 BOE from the quarter a year ago.
Excluding Hugoton, domestic daily production improved 8,000 BOE from the first quarter 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 Midcontinent, 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 first quarter 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 second quarter 2014 worldwide realized oil prices of $100.38 per barrel improved slightly compared to the first quarter 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%, 7% sequentially, reflecting declines in benchmark prices. Price changes at current global prices affect our quarterly earnings before income taxes by $37 million for $1 per barrel change in oil prices and $7 million for $1 per barrel change in NGL prices. A swing by a $0.50 per million BTUs in domestic natural gas prices affects quarterly pre-tax earnings by $25 million.
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 second quarter of 2014, compared to $14.33 per barrel in the first quarter. Domestic operating expenses were higher in the second quarter of this year compared to the first quarter of this year due to higher downhole maintenance and surface operation costs, primarily in the Permian Basin. MENA production costs increased in the second quarter due to higher costs related to the Libya lifting, partially offset by lower surface operations and maintenance costs. Taxes other than on income, which are directly related to product prices, were $2.83 per barrel for the second quarter of 2014 and $2.88 for the first six months of this year, and our second quarter exploration expense was $54 million.
In Chemicals, our second quarter 2014 pre-tax earnings of $133 million were slightly lower than the first quarter results of $136 million and $144 million in the year ago quarter. The seasonal uptick in demand in construction and agriculture markets in the second quarter were more than offset by routine planned plant outages and unplanned customer outages. We expect our third quarter pre-tax earnings to be about $150 million, reflecting anticipated increases in sales and production volumes. In midstream, pre-tax segment earnings were $219 million for the second quarter of this year, compared to $170 million in the first quarter of this year and $48 million in the second quarter 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 first quarter of this year. For the six months of 2014, we generated $5.7 billion of cash flow from operations before changes in working capital. Working capital changes decreased our cash flow from operations by $100 million to $5.6 billion. During the first six months of 2014, cash flow from operations declined approximately $650 million compared to the same period a year ago. The first half of 2014 included a tax payment related to the gain on the sale of the PAGP units, and the first six 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 $5.8 billion. Capital expenditures for the first six months of 2014 were $4.7 billion, net of partner contributions. In the second quarter, we received proceeds of $1.3 billion from the sale of our Hugoton assets and spent about $240 million toward domestic bolt-on acquisitions. After paying dividends of $1.1 billion, buying back $1.6 billion of our company stock and other net flows, our cash balance was $2.4 billion at June 30th. Our debt to capitalization ratio was 13% at the end of the quarter. Our 2014 annualized return on equity was 13%, and return on capital employed was around 11%. The worldwide effective tax rate on core income was 40% for the second quarter of 2014, and we expect the combined worldwide tax rate in the third quarter to remain about the same.
Lastly, I'll outline some guidance for the third quarter. In the domestic business, on April 30th, we closed on the sale of our Hugoton assets. The Hugoton operations produced 18,000 BOE per day in the first quarter and 6,000 BOE per day in the second quarter. For the third quarter, excluding Hugoton, we expect our domestic oil production to grow between 6,000 and 8,000 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 5,000 to 7,000 BOE per day.
For the international business at current prices and assuming normalized operations in Colombia, we expect total international production and 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 third 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 third quarter 2014 exploration expense to be about $100 million pre-tax. I'll now turn the call over to Steve Chazen, 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 Albrecht, 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, a 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 standalone public company. In addition to developments regarding personnel, we continue to make progress on the planned spin-off of the California company.
During the second quarter, we filed the initial Form 10 registration statement and have already responded to comments received from the SEC. CRC has initiated steps to secure its debt financing, which we expect to be completed in the third quarter. We anticipate $6 billion 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 fourth quarter. Upon the spin-off of CRC, Occidental will retain 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.
In the second quarter of 2014, oil production grew 10% compared to the second quarter of last year. The business generated approximately $1.2 billion of cash flow from operations during the first six months of 2014. We expect the CRC management team to present a more detailed view of the business and its growth strategy to investors as it commences its roadshow in the fourth quarter. At Occidental Petroleum, each of the seven 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's 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 with other domestic oil and gas operations in South Texas, our 24.5% interest in the Dolphin project, and a smaller and improved business in the rest of Middle East and North Africa, our operations in Colombia, as well as our midstream operations in the OxyChem 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, two significant projects are nearing their completion. As Willie Chiang will describe in more detail shortly, we expect the BridgeTex Pipeline to start up later this quarter and provide us with an advantaged access to the Gulf Coast for our Permian crude oil production.
We also expect the startup of the Al Hosn Gas project in the fourth quarter. Assuming similar product prices, these two key projects, combined with growing oil volumes from the Permian 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 goal here is to improve the business's 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 Piceance and Williston Basin. We expect to monetize our remaining interest in the general partner of Plains All American, which is valued at approximately $4.5 billion, as well as possibly some other midstream assets when market conditions warrant. Since the end of the third quarter of 2013, we have repurchased more than 26 million shares of the company stock for roughly $2.5 billion, and approximately 20.5 million shares remain available under the current share repurchase authorization. We expect that we will be able to further reduce our share count by roughly 60 million shares through the cash dividend from the CRC separation and by about 25 million shares from the monetization of our remaining interest in the Plains pipeline.
Coupled with the 20.5 million shares in our current repurchase program, we should be able to reduce our total share count by more than 100 million 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 reductions 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 resulting from the expanded Permian Resources development program and shift towards horizontal drilling, the startup of the Al Hosn Gas project, and our participation in several other attractive international growth projects.
These identified and intermediate growth opportunities and projects are capable of more than replacing the production from the spin-off of CRC by the end of 2015. Oxy 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 investments in strategic initiatives. Our improved capital efficiency and operating cost structure, the start-up of operations for BridgeTex, the Al Hosn Gas project, along with the separation of our California business, provide a natural uplift to our return on capital employed. Return on capital employed was 12.2% 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 second quarter, 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 second quarter. This is a 21% increase from a year ago and an 8% increase from last quarter. During the second quarter, our capital expenditures were $490 million. 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 third quarter, 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, then I'll review the quarterly operations in more detail. We've been operating in the Permian Basin for more than 30 years and have considerable knowledge of the depositional history and geology. With 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 understanding of 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 million 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 3D seismic surveys. We are leveraging our learnings from our 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 six wells, which had average initial rates of 850 BOE per day versus prior initial rates of 750. Our recent South Curtis Ranch 2818 well achieved a peak rate of approximately 1,100 BOE per day on gas lift.
At Barilla Draw in the Delaware Basin, our recent Eagle State 28-5 well achieved peak production of 1,620 BOE per day and a 30-day average production of 1,120 BOE per day, significantly higher than our average 30-day production of 830 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 while leveraging our position across our Permian Resources and EOR businesses. These contracts ensure the availability of productive resources at competitive costs 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 2016.
We have expanded our completion capacity to four 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 drill the vertical section of the well with a smaller fit-for-purpose drilling rig, and following the vertical section, we use 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 costs.
We have reduced drilling costs in South Curtis Ranch by 24% since the end of last year. 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 six fracs, including one zipper frac using this new system. We're 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 be fully operational by September, 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 on 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 Barilla Draw area in Reeves County, I'm pleased to report that in the second quarter, we drilled 10 horizontal wells and completed seven wells, whose initial production rates for the Wolfcamp A and B matched the 1,150 BOE per day achieved in the first quarter. 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 2014. We continue to increase efficiency and expect our average well cost of $8.5 million 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 second quarter and placed 21 horizontal wells on production. We will drill an additional 55 horizontal wells in the second half of 2014. Our average drill time for the horizontals is 27 days per well, with total drilling and completion cost averaging $7 million per well. With the knowledge gained, we are transitioning from appraisal to accelerated development in our merchant fields. As a result of the strong performance this year, we are increasing our 2014 production growth expectation to between 15% and 18% from the previous 13%-15%. In addition, we are increasing Permian Resources capital by $200 million to $1.9 billion. 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 Willy 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 to market, 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 third-party volumes to market. We have the scale to drive key strategies in the Permian Basin. 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 midstream assets are shown in slide 33. These are supplemented with contracted capacity on third-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, 278,000 barrels a day of crude, 72,000 barrels a day of NGL, and over 700 million cubic feet a day of gas. We also market third-party crude and NGL volumes, focusing on parties whose supply is located near our transportation and storage assets.
These third-party volumes are significant and add in excess of 200,000 barrels a day for third-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 their assets. We also have gas processing plants, CO2 fields, and facilities. We process equity and third-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 1,800 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 purchase 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 million 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 are focusing on two new key takeaway points, Colorado City, which is the origin of our BridgeTex Pipeline, which we are jointly developing with Magellan, and the Midland south exit, which is the origin to third-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 are working on options to handle the growing light crude production in the Delaware Basin in 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 BridgeTex Pipeline, which is expected to start up later this quarter.
The 450-mile pipeline will be capable of transporting approximately 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-2015, our midstream unit will have access to long-term cost advantage takeaway capacity. As a major producer in the Permian Basin, we have 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 have shown Midland WTI pricing compared to Cushing WTI and the U.S. Gulf Coast LLS markets for the period of 2009 through today.
You can see how the differentials were at transportation parity in a market with adequate takeaway capacity. Now note the differentials widening significantly as the supply and demand balance tighten in a takeaway-constrained market. We have seen Midland LLS differentials as wide as $30 a barrel in January 2012 and January 2013 during the winter refinery maintenance periods. This year, we have 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 2013. With the upcoming completion of BridgeTex and the startup of Cactus Pipeline by mid-2015, we 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 three times our current equity production from the Permian Basin. We will also have access to key markets and options to protect our Permian crude premiums. Let me give you an update on our Ingleside Energy Center in Corpus Christi. This is the former naval station that we purchased in late 2012, which is located outside of the congested ship channel near the mouth of Corpus Christi Bay. We are 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 2 million-4 million barrels of storage and also provides flexibility to accommodate future processing facility options on-site or at a nearby OxyChem complex. We have sanctioned both projects and expect the LPG propane terminal to be complete mid-2015 and the first phase of the crude condensate terminal will be completed the first half of 2016. 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 six Permian producers based on the available public information we were able to pull. You can see we have 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 pipelines 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 constraints. You can see the reasons we have 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 will turn the call back now to Chris Degner.
Thank you, Willie. Operator, we will now poll for questions.
Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. At this time, we will pause momentarily to assemble our roster. 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 lagging what we would expect for peers in the area. My understanding is there's 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? Or are these averages that you feel you've de-risked 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. I've got a follow-up, please.
Yeah, Doug, some of the issues have been associated with at what point in the flow back and production process of the well do we take the test? Some of our teams have been turning in 24-hour 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. That's why we've been aggressively here recently trying to try new things with respect of our frack designs to improve our performance.
In the Midland Basin, South Curtis Ranch, we are getting better, we're testing not only frack designs in terms of fluids and proppant volumes, rates, and things like that, all of which are helping us to improve. We have discovered that our cluster spacing was not optimum for the initial fracks that we've done there. We're confident that going forward, our South Curtis Ranch performance is going to improve. 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. We're confident that there, we've gotten closer to figuring out the right completion technology and the right not only proppant concentrations, sand total volumes, and rates, but also the design of the total job.
In the Texas Delaware, we've actually increased our proppant volumes by about 20% and our fluid injection volumes by about 50%. We've also increased our rate there. We expect continuing good performance and maybe even better performance there. In fact, it's in the Texas Delaware where we've added most of the 2,500 new well locations that we've added since the beginning of the year. While in Texas Delaware, we feel like we're doing a great job. We know we 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.
Right now, about 45% of the 7,000 wells are in the Wolfcamp. 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 one and a half years or less. In southeast New Mexico, we're starting to see some good performance there in the Bone Spring. 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. Steve, my follow-up, hopefully quickly, is the Middle Eastern process. You have a pretty material contract expiring in Oman next year. Obviously, things are moving on this year in terms of absence of news flow on the disposal process. My understanding is you may have things maybe 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 three separate transactions completed over the next, let's say, 12 months.
Yeah, I think one of the transactions is moving along very well. 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. 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. There, there's 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 part and parcel with your Mideast negotiations? Could you guys just elaborate on that a little bit?
I think there's two parts there. We have some new contracts in Colombia for heavy oil, which I think we're pretty enthused about. I think those are pretty much there. They're away from some of the areas where we've had political difficulties, if you want to call them that. I think those are in pretty good shape. Obviously, 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 and a partnership with the local government. 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. I guess just in the Permian, you guys, you clearly have a dramatic acceleration of the rig count over the next couple 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 seeing there in terms of service costs?
We're definitely going to be able to get up to at least 54 rigs by 2016. Our current plan is to go to 45. However, we have the options in place to go to 54. That's not really at risk for us right now. We know we can achieve it on the drilling rig side. The reason we have that range there, we've got 47 in our plan for 2016. The reason on the slide that the seven additional are gray, 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 support services outside the drilling rig that can support 47.
It's just a matter of can we get to the 54. We're working on that plan now. Service cost , we're still trying to manage that. Costs in the basin are going up as demand increases. We're trying to leverage our size to minimize the increases that we're seeing.
Yeah. There's also productivity gains from this, too. I think we've 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. I think the productivity gain should more than offset whatever modest inflation there is in the cost.
Okay. That's helpful for sure. 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, and I reiterated this morning, that we're still looking at options for the Piceance and the Williston Basin. Maybe a little more activity in one of those. We don't know yet. 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. 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? Have you drilled two-mile laterals, or are you extending the lateral length? 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. 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. Two of the challenges there are, as I said, at what point have you drilled so much that you start destroying value in terms of just the friction effects of the longer laterals. 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.
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.
We're maybe a little different focus than some other people. I think we focus on our finding cost calculation rather than the IP calculation. 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. That's just not the way we think about things. A small producer may be more interested in IPs.
Okay. That's helpful. I guess still in the Delaware, what are you seeing from an oil gas mix in your Wolfcamp wells there? 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%-80% oil in the Texas Delaware. In most cases, we're seeing above 75%.
We're a little pickier, maybe we have better acreage than some other people who are doing a fair amount, get gassier results.
Okay.
You can see that our oil is rising and our gas isn't, if you just look at the numbers we've given you. We're basically a little pickier than some other people who are, maybe that's all they got, so they're drilling gassier wells.
Okay. No, that's helpful. 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? What's going to be the primary, I guess, governing factors on the potential to maybe even show upside over that three-year window?
Well, we think on the production numbers we've given, we have considerable upside just with the drilling we're showing. Putting that aside, it's a return-based business and we'd just as soon let other people make mistakes and learn from that before we expand our footprint a lot. 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 two as people drill these gassier wells. You could wind up with a bad situation.
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.
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 Basin drilling situation, more in terms of managing the drilling inventory. 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. Obviously, doubling the rig count will take that back to a 10-year inventory. I also assume you're probably going to be adding locations over time. How do you actually then balance the amount of drilling inventory that you have from an NPV basis? What I'm really getting at more broadly, do you see divestiture opportunities within the Permian Basin as well as potential acquisitions?
Yeah. 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. Because there's so many horizons, there's so much there's so much oil available in the system, so we didn't divest that much, but I regret every acre. I think that while I'm here, we're not going to be divesting anything. I think the program that Vicki's outlined is sort of the minimum program. That's just 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. I think we could accelerate the program further. This is what we're talking about right 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 two or three years. While we have, as Willie pointed out, lots of oil takeaway capacity, a lot better positioned than most people, I think. 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 a little 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 business. I'm not really worried about cost because I think productivity improvements will more than offset the cost.
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 the amount of shares that you'll be able to repurchase from the transaction has went to 60 million from a range of 40-50. My question is: Is this going to be related to the just under 20% retention of equity and the exchange over time? Do you still expect to take a $5 billion dividend out?
No. Dividend's $6 billion.
Okay.
We haven't counted the shares in the exchange. It's simply, we got our modelers out, they divided $6 billion by $100 to come up with the 60 million shares.
Okay. The dividend went from-
We didn't pay a lot for that advice, so.
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. 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, our options are sort of limited because it's part of a tax ruling. If we exchange it for Oxy shares, in other words, put an ad in the paper that 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, there isn't that kind of amount of debt around to do that. The third 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. Our preference would be to do the exchange offer.
Basically, it's a split off of the 19.9% in terms. What we did was we sort of guessed at how much. We haven't included that number in our 60 million shares. There'll be some number of shares that we'll exchange as CRC shares for Oxy shares, and we do that without paying any tax.
The follow-on slide, which is 21, where you show the famous $60 million, says clearly that you don't include anything from MENA.
Yeah.
I was just wondering why it says it does 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.
It's just in a rounding.
Yeah, I figured. I just wanted to confirm that.
Yeah.
The fact that your list of mistakes just made me think of Lindsay Lohan, actually, funnily enough, but there you go. Would that involve you potentially making an acquisition in the Permian, further acquisitions of scale?
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 at six, seven 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 would be a different story. Absent a huge reduction in the public market values of these companies, I can't even imagine doing one. Hopefully my successors are well trained enough not to do anything stupid, too.
Yeah. Thank you. Then finally from me, in the past, you've sort of openly debated the buyback, the benefits and merits of a buyback. Is there some sort of price sensitivity to this or is this going to be a fairly blind process? I'll leave it there.
No. Hopefully it won't be a stupid process. I think that's what you're Blind is, I guess, another word for stupid.
Well, no, 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. Yeah, we're going to buy back the shares ultimately, it also depends on the price. We would expect that during the process of divesting of the California company, the stock, during the confusion, the Oxy stock will trade at what we would view as a discounted value, we would expect that we could buy a lot of shares during that period. I'd be pleased to be wrong, that would be a reasonable expectation during that period.
I guess what I was driving at, partly as well, is 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 billion to work? Yeah. Could you put $2 billion to work? Maybe. Could it put $3 billion to work? No. I think we got a plan that we can execute efficiently. We could probably do a little better as things progress. I think the answer is yeah, we could do that, but not for very long.
Thanks so much.
Thanks.
Our next question comes from Edward Westlake of Credit Suisse. Please go ahead.
Yeah. One question on the Permian. Vicki, obviously you've broken out your current vertical and horizontal, and then you've explained how doing the two activities separately makes sense. As you look at that rig count chart, should we assume you're still going to have the same sort of ratio? 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 six or seven vertical rigs at any given time in the future. The bulk of the 47 to 54 that we'll have, I would expect only about six or seven of those to be vertical.
Right. Obviously you've given us the 7,000 locations, and Jason was probing on that. As you ramp up the rigs, your inventory is going to drop, I think perhaps a little bit faster. 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 a fantastic sweet spot in the Texas Delaware. It feels like a lot of your acreage is over in the Bone Spring, to maybe talk about how the returns would change as you shifted those rigs around through the program.
Yeah, let me say 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. 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. I expect that inventory to grow fairly significantly over the next couple of years. 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 our focus areas so that we can make sure that we accelerate efficiently. 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. Some appraisal work, there's some areas where we haven't even begun our appraisal work.
just a question on the midstream. I know you sort of signaled you're going to be selling the Plains All American GP. Seems like it's time to build another one given the amount of midstream assets that you are still building. 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 two. One is the tariff streams. Those are, once you build the pipeline, they're sort of not very interesting. The other is sort of the trading or streams, our ability to move the oil to different spots. We would just as soon retain the contracted volume streams and ultimately dispose of the tariff streams, if you will. I think as far as building another line, I think we got plenty for us. We're three times what we currently produce. We got plenty for us. We'll see how it goes. Again, I'm focused about putting the midstream money right now into 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. Our view is we need to make sure that our $100 oil gets moved, and worry a little less about the $0.50 fee. We're focused on making sure that by building this stuff out, we made it better for everybody in the Basin.
And then-
Then on the gas, we expect to do the same thing.
Just the final question. You've seen these, I guess royalty interest, mineral interest streams start to get traded independently of the companies who own them. Maybe just a reminder of where your royalty position is in some of your legacy acreage.
Yeah. 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. Putting that aside, 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. If we were to dispose of that in some way, that would hurt our finding costs and our margins would shrink, our present worth would shrink, 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 third parties. We don't really know the number at this point. They're counting the checks, I think, just to try to figure it out.
Excluding California, the royalty income is somewhere in the range of $300 million a year, to 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. If somebody'd like to pay 15 times cash flow, I think we're game. On the other hand, where it affects our base business, we'd just as soon keep it because I think it'll hurt us and our finding costs going forward.
Thanks. Very clear and helpful. Thank you.
Thanks.
Our last question comes from John Herrlin of Societe Generale. Please go ahead.
Close enough.
The operator is not French, obviously.
Yeah. 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 into pad drilling in 2015.
Which will also help with the-
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.
Right. I was just wondering how quickly you'd be improving your efficiencies. What about staffing? Given 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. So far, we've been able to add the people that we need as we progress.
Okay, great. Last one from me, Steve. You talked about addressing the midstream. Does this mean MLP or just outright sale?
Well, 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 is now concluded. Thank you for attending today's presentation.