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Occidental Petroleum Corporation (NYSE:OXY)

Q2 2014 Earnings Conference Call

July 31, 2014 10:00 AM ET

Executives

Chris Degner – SVP, IR and Treasurer

Chris Stavros – CFO

Steve Chazen – President and CEO

Vicki Hollub – President, Oil and Gas, Americas

Willie Chiang – EVP, Operations

Analysts

Doug Leggate – Bank of America Merrill Lynch

Leo Mariani – RBC

Ryan Todd – Deutsche Bank

Jason Gammel – Jefferies

Paul Sankey – Wolfe Research

Ed Westlake – Credit Suisse

John Harlan – Societe Generale

Operator

Good morning. And welcome to the Occidental Petroleum Corporation Second Quarter Earnings Conference Call. All participants will be in a listen-only mode. (Operator Instructions). 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.

Chris Degner

Thank you, Ed and good morning, everyone. And thanks 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; Willie Chiang, Oxy’s 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 Willie Chiang 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 on 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 of our website at www.oxy.com.

I’ll now turn the call over to Chris Stavros. Chris, please go ahead.

Chris Stavros

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 the alluded earnings per share of $1.79 for the second quarter of 2014, an improvement of 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 it’s 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 and the second quarter of last year. In the second quarter of 2014, after tax core income for 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 it’s a result of increased down-hole maintenance and surface operation costs.

International after tax core income was $576 million for the second quarter of 2014 and 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 result 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 BOEs 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 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 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 Colombia did to pipeline disruptions from insurgent activity.

Our second quarter 2014 worldwide realized oil prices of $100.38 per barrels 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 the Permian Basin. Realized prices for domestic for NGL and natural gas production fell at 6% and 7% sequentially reflecting declines in benchmark prices.

Price changes at current global prices affect our quarterly earnings before income taxes by $37 million for a $1 per barrel change in oil prices and $7 million for $1 per barrel change in NGL prices, a swing of $0.50 per million BTUs in domestic natural gas prices that’s quarterly pre-tax earnings by $25 million. These prices 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 this year compared to the first quarter of this year due to higher downhaul 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 up-tick 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 in 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 that’s been about $240 million towards domestic Bolton 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 30. 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 to combine 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 30, 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 6,000 and 8,000 barrels per day sequentially, roughly 10% on an annualized basis. We would expect this domestic oil production growth rate to accelerate over time.

Domestic NGL productions 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, the current prices and assuming normalized operations in Colombia, we expect total international production in 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 for 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, who will provide an update on some of our strategic initiatives.

Steve Chazen

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, had an independent oil and gas producer.

With these appointments, most of the key roles in the organization have been filled. And we’re confident that their ability to succeed as a standalone public company.

In addition to the developments regarding personnel, we continue to make progress in the plant spin-off of the California Company. During the second quarter we filed the initial Form 10 registration statement and have already responded to the comments received in 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, it’s a tax free dividend and shortly prior to completion of the spin-off, which we expected to occur in the fourth quarter.

On 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 retained for Occidental shares.

The California business continues to perform well and its executing on its oil and gas production growth strategy. The second quarter of 2014 oil production grew 10% compared to the second quarter of last year and 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 road show in the fourth quarter.

At Occidental Petroleum, each of the seven members, 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 continue. Oxy’s core businesses and we focused on delivering moderate volume growth, generating higher earnings and cash flow per share and leading to improved financial returns.

And for completion of the strategic initiatives, we laid out last fall our area 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, losing our well cost and further enhancing our oil price realizations. Vicki Hollub will provide a further update on the Permian resources business shortly.

Our Permian Basin operation with Barilla Draw with other domestic oil and gas operations in South Texas, are 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 also supported our ability to grow our dividends for our shareholders. Operations with our 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 more details shortly, we expect to BridgeTex’s pipeline to start-up later this quarter, provide with an advantaged access to the Gulf Coast for our Permian crude oil production.

We also expect start-up of the Al Hosn Gas Project in the fourth quarter. Assuming similar product prices these two key projects combined with growing oil volumes in the Permian resources development program should provide us with a meaningful earnings and cash flow per share growth in the 2015.

Finally, as a part of our strategic initiatives, we’ll continue to focus on raising cash from our lower growth and lower margin assets.

In the Middle East we continue to make progress and negotiations with our partners, we will reduce our exposure to the region. Our goal here is to improve the businesses’ 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’re continuing to explore strategic alternatives for assets and the Piceance in Williston Basin.

We expect to monetize our remaining interest in general partner Plains all American which is valued at approximately $4.5 billion as well as possibly some other mid-stream 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 of roughly $2.5 billion and approximately 20.5 million shares remain available under the current share repurchase authorization.

We expect that we’ll be able to further reduce our share count by roughly 60 million shares for the cash dividend from the CRC separation and about 25 million shares to monetization of our remaining interest in the Plains pipeline. Coupled with 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 this share repurchase-ability will occur after the spin-off of CRC. These amounts do not include the ability to repurchase additional shares through proceeds we’re seeing from the sale, a portion of our interest in the Middle East, share reductions in exchange of our remaining interest in CRC or the monetization of other assets.

We expect Oxy’s remaining businesses deliver moderate volume growth result the expanded Permian resource development program and shift towards horizontal drilling to start-up the Al-Hosn gas project and our participation of several other attractive international growth projects.

These identified an intermediate growth opportunities and projects capable of more than replacing the production from the spin-off of CRC by the end of 2015. And 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 investment strategic initiatives. Our improved capital efficiency and operating cost structure, start-up of operations for BridgeTex’s, the Al-Hosn gas projects along the separation of our California business provide a natural up-lift to our return on capital employed. Return on capital employed was 12.2% in 2013 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.

Vicki Hollub

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 year 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. We drilled 87 wells including 42 horizontals.

Year-to-date we have drilled a total 67 horizontal wells of which 43 have been completed and put on production. 38 wells are currently waiting on completion or a hook-up. In the third quarter we planned 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 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 of geology.

With that base knowledge we have been and are continuing to make significant investments to assess the rock and fluid properties in our own conventional reservoirs across our acreage. This is helping us to develop a better understanding of the key 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 Petro-physical models to characterize perspective benches and target landing zones within each bench.

As a result of our work today, we have now identified over 7,000 drilling locations across our 2 million net perspective acres. This is an increase 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 hole cores, cuttings, advanced log sweeps, micro-size mixed surveys and 3D-siesmic surveys.

We’re 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 still development and well design alternatives including optimization of well spacing, lateral length and cluster spacing. Additionally we have also increased profit 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 full field development and product growth. We have ordered long lead-time equipment and figured favorable material and service contracts by leveraging our position across our Permian resources and EOR businesses.

These contracts ensure the availability of 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 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 compressed 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 do all 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 in 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 improved cost. We have reduced drilling cost 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. Today 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 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 Barilla Draw and Reeves County, I’m pleased to report that in the second quarter we drilled 10 horizontal wells and completed 7 wells with initial production rate for the Wolfcamp A and B, match the 1,150 BOE per day achieved in the first quarter.

In the area highlighted on the map where we held over 35,000 net surface acres, we’ll 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 held approximately 90,000 net surface acres, we’re 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 field.

As a result of the strong performance this year, we’re increasing our 2014 production growth expectations to be between 15% and 18% from the previous 13% to 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 result in 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 capacities that is a unique competitive advantage.

I will now turn the call over to Willie to discuss in more detail.

Willie Chiang

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. And then spend the majority of my time to share our strategies to support Permian Basin growth that you just heard about from Vicki.

We strongly believe in 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.

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 Midstream assets are shown in slide 33, these are supplemented with contracted capacity on third party assets, all of which allows to market substantially all of Oxy’s domestic oil, NGLs and gas production, comprise 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 an excess of 200,000 barrels a day for third party, crude and NGL volumes.

This aggregation of volume, both service a need for producers and end-users and allows us to better utilize and optimize our assets. We also have gas processing plants to 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 in 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’re focusing on two new takeaway points, Colorado City, which is the origin of our BridgeTex’s pipeline which we’re jointly developing with Magellan. In the Midland South exit which is the origin to third party pipelines Long-Horn 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 Corps 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 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’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 in the U.S. Gulf Coast LLS markers for the period of 2009 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 tighten in a takeaway constrained market. We have seen Midland LLS differentials as wide as $30 a barrel in January 2012, in 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 2013.

With the upcoming completion of BridgeTex, in the start-up of Cactus pipeline in 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’ve 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’ll 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 formal 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’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 2 million to 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 in the first phase of the crude condensate terminal to be completed in 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’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 startup 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’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.

Chris Degner

Thank you, Willie. Operator, we’ll now pull for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). And our first question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.

Doug Leggate – Bank of America Merrill Lynch

Thanks, good morning everyone and 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 wagging what we would expect for peers in the area. And my understanding is that some kind of reporting issues with you guys. I wonder if you could share something with us.

And as it relates to the wells that you have drilled prior the presentation today, can you isolate where in the Permian you’re drilling in terms of which horizon out of 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 kinds of results across the 2,000 plus locations? And I’ve got a follow-up please.

Vicki Hollub

Yes, Doug. Some of our reporting issues have been associated with what point in the flow back and production process of the well that 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 in production. And that’s why we’ve been aggressively here recently trying to try new things with respect of 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 optimal 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 profit volumes by about 20% 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 new 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 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.

Doug Leggate – Bank of America Merrill Lynch

On de-risking Vicki, of the locations on multiple benches or horizons I should say?

Vicki Hollub

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 one and half 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.

Doug Leggate – Bank of America Merrill Lynch

Thank you. And Steve, my follow-up hopefully quickly is, in the Middle Eastern process, you have a pretty major material contract expiring in Oman next year. And obviously things are kind of moving on this year in terms of obvious of news flow and the disposal process.

My understanding as you may have things maybe moving a little quicker than perhaps you’ve been prepared to see previously. I just wonder if you could give us an update on your company as where everyone maybe getting the three separate transactions completed over the next let’s say 12 months?

Steve Chazen

Yes, I think one of the transactions is moving on 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.

Doug Leggate – Bank of America Merrill Lynch

I’ll let someone else jump. Thanks very much.

Steve Chazen

Thank you.

Operator

Thank you. Our next question comes from Leo Mariani of RBC. Please go ahead.

Leo Mariani – RBC

Hi guys, you referred a little bit 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 many negotiations? Could you guys just elaborate on that a little bit?

Steve Chazen

I think there is two 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 I 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 is no growth or smaller reductions in areas where there is growth and a 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 is potential for that.

Leo Mariani – RBC

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 maybe secured at this time by contract and what are you kind of seeing there in terms of service cost?

Vicki Hollub

We’re definitely going to be able to get up to at least 54 rigs and by 2016. That’s – but 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 seven 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 area 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 to 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.

Leo Mariani – RBC

Okay.

Steve Chazen

There is, also productivity gains from this too. So, I think we’re – we’ve saved – 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 with the productivity gains should more than offset whatever modest inflation there is in the cost.

Leo Mariani – RBC

Okay, that’s helpful for sure. And can you guys just elaborate on other assets that you might be thinking about disposing we 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?

Steve Chazen

I think we’ve said that – reiterated this morning that we’re still looking at options for the Piceance in the Williston Basin, might be a little more activity in one of those, we don’t know yet.

And we also said that buried in the comments was 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.

Leo Mariani – RBC

Okay. Thanks, that’s helpful.

Operator

Our next question comes from Ryan Todd of Deutsche Bank. Please go ahead.

Ryan Todd – Deutsche Bank

Great, thanks. If I could ask maybe a little bit more on the Delaware Basin, and I appreciate all the detail. Can you talk a little bit about your use of long laterals, I mean, have you drilled two-mile laterals or are you extending the lateral lengths. And if so, how much of your acreage there in the basin do you think would be conducive to longer laterals?

Vicki Hollub

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 productivity from the lateral lengths that we’re drilling. We haven’t really drilled much yet over 4,200 feet to the challenges there as I said, at what point 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 setup your opportunities to go with longer laterals.

But currently, we’re seeing that probably it’s more likely to meet 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.

Steve Chazen

I mean, maybe a little 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 in order to lengthen the laterals may cost us more money. You might get more IP but maybe at a cost of a higher finding cost. We’re just – it’s not the way we think about things. Some small producer may be more interested in IT.

Ryan Todd – Deutsche Bank

Okay, that’s helpful. And have you seen – I guess still on the Delaware, have you seen, where are you seeing from an oil and gas mix in your Wolfcamp well there and you’re seeing much variation across the extent of your acreage?

Vicki Hollub

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%.

Steve Chazen

We’re a little pickier and maybe we have better acreage to some other people who are doing a fair amount, they get gassier results.

Ryan Todd – Deutsche Bank

Okay.

Steve Chazen

You can see that our oil is rising and our gas isn’t if you just looked 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.

Ryan Todd – Deutsche Bank

Okay. 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? What’s going to be the primary I guess governing factors on the potential to maybe even show upside over that three-year window?

Steve Chazen

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’ve just assumed, learned lot of people make mistakes and learned from them before we expand our footprint. But there is, also other logistical issues in the basin.

And yes, we want to make sure that we have takeaway capacity for the oil, and more concerned frankly about takeaway capacity for gas. You’re not going to be able to flare the gas. And the gas production, the base is likely to grow sharply in the next year or two as people drill these gassier wells. And so you could wind up with a bad situation.

So, one of our major focus is just 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.

Ryan Todd – Deutsche Bank

Great. Well, thanks, I appreciate the help. I’ll leave it there.

Steve Chazen

Thank you.

Operator

Our next question comes from Jason Gammel of Jefferies. Please go ahead.

Jason Gammel – Jefferies

Yes, 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 last. You have about 20-year inventory, obviously 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 MPV basis, and what I’m really getting out more broadly, do you see divestiture opportunities within the Permian Basin as well as potential acquisitions?

Steve Chazen

Yes. If I look at the list of mistakes I’ve made over the last 20 years, the mistake I’ve made most is investing anything into Permian Basin. And because there is so many horizons, there are so much layer, there is so much oil available to 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 will be more opportunities because we’re sort of everywhere. I think that – 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 out 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, 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.

I’m 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 deeding concern is that the crowding in the business, I’m not really worried about cost because I think productivity improvements are more lost at the cost.

Jason Gammel – Jefferies

Great, that’s pretty clear. If I could just ask 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 the range of 40 million to 50 million.

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 billion dividend out?

Steve Chazen

No, dividend $ billion.

Jason Gammel – Jefferies

Okay.

Steve Chazen

And so we haven’t counted the shares and the exchange. So we’re simply, our – we got our modelers out and so they divide $6 billion by $100 mop it to 60 million shares. We didn’t pay a lot for that advice.

Jason Gammel – Jefferies

Very good, I think I understand now.

Steve Chazen

Okay, thank you.

Operator

Our next question comes from Paul Sankey of Wolfe Research. Please go ahead.

Paul Sankey – Wolfe Research

Hi everyone, and congratulations to those who have new roles. I see, I kind of didn’t understand Steve that last point, believe it or not, the exchange of it has be completed within 18 months and any proceeds from that I guess is the word would be used for buyback – additional buyback?

Steve Chazen

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 tactual link. So, if we exchange it for Oxy shares, now it was – ad 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 could exchange it for debt, but there isn’t that kind of munch there around to do that. If we do anything – the third alternative would be simply distributed 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, 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 million shares. But there would be some number of shares that we’ll exchange the CRC shares for Oxy shares and we do that without paying any tax.

Paul Sankey – Wolfe Research

Okay. And the follow-on slide which is 21, where you show that the same as 60 million says clearly that you don’t include anything from MENA. I was just wondering why is that does not reflect that reduction, does that mean that you’re going to pay down debt as well?

Steve Chazen

Well, there is a small amount of debt reduction probably.

Paul Sankey – Wolfe Research

Okay.

Steve Chazen

It’s just in the rounding.

Paul Sankey – Wolfe Research

Yes, I figured that I just wanted to confirm that. So, the fact that your list of mistakes just maybe think of Lindsay Lohan I see funny enough. But there you go, would that involve you potentially making an acquisition in the permit further acquisitions of there? Thanks.

Steve Chazen

Actually the Permian acquisition scale is now – 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 what we traded six or seven times wherever we want to say the cash flow.

And the acquisitions are very dilutive and I can’t imagine doing one. I suppose if there is a collapse in oil price or something like that that would be a different story. But actually a huge reduction in the public market values for these companies, I can’t even imagine doing one, I don’t imagine that hopefully my successors are well trained enough not to do anything stupid too.

Paul Sankey – Wolfe Research

Yes. And then finally from me, thank you. And then finally from me, in the past you’ve sort of openly debated the buyback as the benefits and the merits of a buyback. Is there some sort of price sensitivity to this or is this going to be a fairly blind part? And I’ll leave it there.

Steve Chazen

No, hopefully it won’t be a stupid process I think that’s what you’re blind I guess another word for stupid.

Paul Sankey – Wolfe Research

Well, I think you’ve said in the past that there is a fair value that you believe?

Steve Chazen

There is 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 California company, the stock will during the confusion will trade at the Oxy stock will trade at some what we would view as discounted value. And we would expect that a – we could buy a lot of shares during that period. And we’re pleased to be wrong but that would be a reasonable expectation during that period.

Paul Sankey – Wolfe Research

I guess what I was driving at partly as well as the potential for you to spend more money organically to grow faster probably as to buyback?

Steve Chazen

More but not materially more I think is the answer. Could you put another $1 billion to work, yes, could you put $2 billion to work, maybe, could you 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. So I think the answer is yes, we could do that but not for very long.

Paul Sankey – Wolfe Research

Thanks very much.

Steve Chazen

Thanks.

Operator

Our next question comes from Ed Westlake of Credit Suisse. Please go ahead.

Ed Westlake – Credit Suisse

Yes, one question on the Permian Vicki, just obviously you’ve broken out your current vertical and horizontal and then you’ve explained how doing the two-activity 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 or maybe help us understand how many vertical rigs are going to be in that 47 plus 7?

Vicki Hollub

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.

Ed Westlake – Credit Suisse

Right. And obviously you’ve given us 7,000 locations and Jason was prepping 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?

I mean, 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 equity is over in the Bone Springs and so to maybe talk about how the returns would change as you shifted those rigs around through the program?

Vicki Hollub

Yes, 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 to our initial step of exploration and then appraisal before we’re adding, and 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 our focus area 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.

Ed Westlake – Credit Suisse

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 of 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?

Steve Chazen

Yes, I think that you just have to split the revenue streams that come out of us into two. One is the Terra 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 stream’s ability to move the oil at different spots. We would just assume to retain the contracted volume streams and ultimately dispose of the Terra streams if you will.

So, I think as far as building another line, I think we got plenty for us, we’re three 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 movement 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 – by building this stuff out, we made it better for everybody in the Basin. And then, on the gas we expect to do the same thing.

Ed Westlake – Credit Suisse

And then just a final question. You’ve seen these I guess royalty interest, mineral interest stream start to get traded independently of the companies or maybe just a reminder of where your royalty position is in some of your legacy acreage?

Steve Chazen

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 is, 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 to dispose that in some way, that would hurt our finding costs and our margins would shrink, our present worth would shrink, that may not make in that – and our reserves will go down because you’re economic limit is reached sooner.

On the other hand, we have a fair amount of production where we just get checks from third parties. And we don’t really know the number at this point, I mean, it’s not – they’re counting the checks I think they try to figure it out. But for the – excluding California, the royalty income is somewhere in the range of $300 million a year and to find some way. We just have to go 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 like the basis team times cash flow. I think we’re game. On the other hand, where it affects our base business, we just don’t keep it because I think it will hurt us in our finding cost going forward.

Ed Westlake – Credit Suisse

Thanks, very clear and helpful. Thank you.

Steve Chazen

Thanks.

Operator

Our last question comes from John Harlan of Societe Generale. Please go ahead.

John Harlan – Societe Generale

Close enough.

Steve Chazen

The operator is not French obviously.

John Harlan – Societe Generale

Yes, thanks Steve. In the Permian, how much of your drilling activity is pad based at this stage?

Steve Chazen

Vicki.

Vicki Hollub

Because of the early stage that we’re in and 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 independent drilling in 2015.

John Harlan – Societe Generale

Which will also help, okay.

Vicki Hollub

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.

John Harlan – Societe Generale

Right. I was just wondering how quickly you’d be improving efficiencies. What about staffing, given the ramp in the Permian, do you think you have enough people?

Vicki Hollub

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.

John Harlan – Societe Generale

Okay, great. Last one from me, Steve, you talked about addressing the Midstream. Does this mean MLP or just outright sale?

Steve Chazen

Well, I mean, it doesn’t – if somebody would give you MLP multiple and 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 some other way, I think we can do an MLP.

John Harlan – Societe Generale

Great. Thank you.

Steve Chazen

Thanks.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Degner, for any closing remarks.

Chris Degner

Hi, thank you everyone for listening. I know it’s been a busy day for you all. We’ll be available at New York for your questions. Thanks.

Steve Chazen

Thanks.

Operator

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.

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