西方石油 (OXY) 2014 Q2 法說會逐字稿

Good morning.

And welcome to the Occidental Petroleum Corporation's Second Quarter Earnings Conference Call.

(Operator Instructions)

Please note this event is being recorded.

I would now like to turn the conference over to Mr. Chris Degner.

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, EVP & CFO; Vicki Hollub, President, Oil and Gas in the Americas; Willie Chiang, Executive Vice President of Operations; and Sandy Lowe, President of 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 in 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 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 programs.

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 8000 barrels per day or about 3%.

Oil and Gas core after tax earnings for the second quarter of 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 in 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 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 listing 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 9000 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 8000 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 commodities specific basis our domestic oil production grew by 8000 barrels per day with 3000 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 1000 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% 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 $1 per barrel change in oil prices and $7 million for a $1 per barrel change in NGL prices.

A swing by $0.50 per million BTU's 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 down hole 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 cost.

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.

This seasonal up-tick in demand in construction and agricultural 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 the 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 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 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 our -- 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 6000 BOE per day in the second quarter.

For the third quarter, excluding Hugoton, we expect our domestic oil production to grow between 6000 and 8000 barrels per day sequentially or roughly 10% on an annualized basis.

We would expect this domestic oil production growth rate to accelerate over time.

Domestic NGL production should see a modest increase although this should be somewhat offset or equally offset by lower natural gas production volumes.

We expect our total domestic production to grow between 5000 to 7,000 BOE per day.

For the International business the 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 companywide production in the third quarter is expected to increase by 15,000 to 17,000 BOE per day sequentially or 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.

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 and deep understanding of operations at an independent oil and gas producer.

With these appointments, most of the key roles in the organization have been filled and we are confident in their ability to succeed as a stand-alone public company.

In addition to developments regarding personnel, we continue to make progress in the planned spinoff 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 and shortly prior to completion of the spinoff, which we expect to occur in the fourth quarter.

Upon the spinoff 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 is executing in 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 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 spinoff, Oxy's philosophy, discipline and 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 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 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 will be rounded out with other domestic oil and gas operations in South Texas, our 24.5% in the Dolphin project and a smaller and improved business in the rest of Middle East, North America, our operations in Columbia as well as are Midstream operations in the chemical business.

Each of these businesses identified opportunities to drive earnings and cash flow growth and also support our ability to grow our dividends for our shareholders.

Operations without profitable growth will see minimal capital spending or will be disposed of.

After several years of significant capital investment, 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 advantaged access to the Gulf Coast for our Permian crude oil production.

We also expect the 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 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 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 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 in 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 account by roughly 60 million shares with a cash dividend from the CRC separation and by about 25 million shares in monetization of our remaining interest in the Plains pipeline.

Coupled with a 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 we've seen from a sale, 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, resolved expanding Permian resource development program and shift towards horizontal drilling to start up the Al Hosn Gas project and our participation in several other attractive international growth projects.

These identified in intermediate growth opportunities and projects capable of more than replacing the production from the spinoff of CRC by the end of 2015.

And Oxy shareholders will still retain the value created from the spinoff as owners of CRC shares.

We expect to generate a higher financial returns going forward as a result of our investment in strategic initiatives, our improved capital efficiency and operating cost structure, start up of operations for BridgeTex, the Al Hosn Gas project along with our 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.

Here 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 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 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 the key geologic parameters that drive productivity such as prosody, 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 perspective 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 perspective acres.

This is an increase of more than 2,500 since the beginning of this year.

We expect to continue to grow the number of locations through our successful exploitation efforts.

We're also conducting an extensive appraisal of high potential benches to optimize our well designs and development plans.

This appraisal work includes collection and analysis of whole cores, cuttings, advanced log suites, microseismic surveys and 3-D seismic surveys.

We are leveraging our learnings from 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 are testing various field development and well design alternatives, including optimization of well spacing, lateral length and cluster spacing.

Additionally, we have also increased propent 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 BOE.

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 30 day average production of 1,120 BOE per day.

Significantly higher than our average 30 day production of 830 BOE of prior wells in the Wolfcamp A and B benches.

With respect to supplies, services and logistics we have secured key resources to efficiently accelerate full field 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 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 compress cycle time.

In early 2014 we implemented a batch drilling program to accelerate and improve the cycle time on our horizontal wells.

In our batch drilling program we drilled a vertical section of the well with a smaller fit for purpose drilling rig and following the vertical section we used a higher capacity directional drilling rig with specialized services to complete the more complex curve 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 improve cost.

We have reduced drilling costs in South Curtis ranch by 24% since the end of last year.

Now for a quick update of our water management strategy.

The Barilla draw system has been pressured up and is operational.

To date we have completed six fracs including one zipper frac using this new system.

We are achieving a cost savings of $2.50 per barrel of water.

In the Midland basin, we are duplicating this effort by installing a water distribution system at West Merchant with delivery rates up to 90,000 barrels per day.

The system will 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 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 ten horizontal wells and completed seven wells with 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 held 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 field.

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% 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 resulting production increase from the incremental capital will primarily impact 2015.

In closing, our 2014 program is designed to delineate and appraise our acreage in order to maximize both ultimate recovery and financial returns.

We're on track to exceed expectations in 2014 and we have the required resources and infrastructure in place to meet our 2016 production target of more than 120,000 BOE per day.

In addition, Oxy has several exciting midstream projects related to our Permian infrastructure and takeaway capacity that is a unique competitive advantage.

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

Thanks, Vicki.

Good morning everyone.

I'd like to give you a very quick overview of our midstream and marketing segment and describe how it literally connects our Oil and Gas production to market.

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

We strongly believe 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 operation is 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 US moving to an abundance of resource and a significant shifting of global supply and demand.

Our Oxy owned domestic midstream is shown on slide 33.

These are supplemented with contracted capacity on third-party assets, all of which allows us to market substantially all of Oxy's domestic oil, NGLs and gas production, comprised of roughly 470 BOEs per day, 278,000 barrels a day 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 our 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 mainland 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 key take away points.

Colorado City, which is the origin of our BridgeTex pipeline, which we're jointly developing with Magellan and 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 Corpus Christi.

It also supplements our existing access to Cushing.

We're working on options to handle the growing like crude production in the Delaware Basin in Southeast New Mexico in order to preserve the Permian crude quality 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.

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 US Gulf Coast LOS markets for the period of 2009 through today.

You can see how the differentials where 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 LOS 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 furthered tightened the supply and demand balance.

The Midland LOS 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 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 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 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'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've sanctioned both projects and expect the LPG propane terminal to be complete mid-2015 and the first phase of the crude condensate terminal 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 ad 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 an approximately $1.50 a barrel better than the group average.

On the same basis we expect to capture an additional $2 plus of value once the BridgeTex and Cactus pipeline start up as a result of our long-term advantaged takeaway capacity.

This reinforces the importance of key infrastructure.

If these new pipelines were not sanctioned the entire basin would suffer continued significant discounts to market due to the infrastructure 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 bid out a strong platform for future opportunities.

Thanks for your attention.

I'll turn the call back now to Chris Degner.

Think you Willie.

Operator, we'll now poll for questions.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions)

Doug Leggate of 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 us.

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, you're well results have been lagging what we would expect for peers in the area.

And at months starting, is there some kind of reporting issue with you guys?

I wonder if you could share something with that as it relates to the wells that you have drilled per the presentation today, can you isolate where in the Permian you are drilling in terms of which horizon or do these averages that you feel you've de-risked multiple sections across your acreage?

A little but more color as to what your confidence level is and the repeatability of these results across the 2,000 plus locations.

And I've got a follow-up.

Yes Doug, some of our reporting issues have been associated with at what point in the flowback and production process of the well do we take the test.

And some of our teams have been turning in 24 hour completion -- the initial completion rates to the Railroad Commission in the state of Texas that are not when the well is fully cleaned up and not necessarily at its peak.

With that said, I'm going to just be honest with you that in some areas, we still are lagging behind our competitors in terms of our initial rates and production.

And that's why we've been aggressively here recently trying to try new things with respect to our frac designs to improve our performance.

In the Midland basin South Curtis Ranch, we are getting better and we're testing not only frac designs in terms of fluids and profit volumes, rates and things like that, all of which are helping us to improve.

But we 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.

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.

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.

On the risking, Vicki, of the locations on multiple benches or Horizons I should say?

Most of our -- about right now about 45% of the 7,000 wells are in the Wolfcamp.

And as you know, we probably, as an industry, know more about the Wolfcamp than any other.

About 20% of our inventory right now is in the Bone Spring in Southeast New Mexico.

Those wells as you know are also doing pretty good.

Where we're seeing -- in Texas Delaware we're seeing payout time periods of 1.5 years or less and in Southeast New Mexico we're starting to see some good performance there in the Bone Spring.

I'd say that right now 65% of our inventory is probably minimal risk in terms of economics and the ability to profitably grow it.

The others are in benches that we still have some work to do.

Thank you.

And Steve, my follow-up, hopefully quickly, is the Middle Eastern process.

You have a pretty good material contract expiring in Oman next year.

And obviously, things are moving on this year in terms of absence of new slow in the disposal process.

My understanding is you may, have things been moving up, moving a little quicker then perhaps you've been prepared to see previously.

Just wondered if you could give us an update on your confidence level and getting the three separate transactions completed over the next 12 months?

I think one of the transactions is moving along very well.

And I think we'll get to resolution here in the easily foreseeable future.

There is the contract extension in Oman which will have to be part and parcel of whatever goes on there, because otherwise it expires in 2015.

So I think it may 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.

I'll let someone else jump.

Thanks very much.

Thank you.

Leo Mariani of RBC.

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 many negotiations?

Could you elaborate on that a little bit?

There's two parts there.

We have some new contracts in Columbia for heavy oil which I think we're pretty enthused about.

I think those are pretty much there-- so those will be -- they're away from some of the areas where we've had political difficulties, if you want to call them that.

Those are 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's growth and a partnership with the local government.

Some of the growth will come out of the partnership with the local government in those areas where there's potential for that.

Okay, that's helpful.

And just in the Permian you guys clearly have a dramatic acceleration of the rig count over the next couple of years here.

Just trying to get a sense of how much of that may be secured at this time by contract and what you're seeing there in terms of service cost?

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 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 grayed, 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 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.

This is also productivity gains from this too.

So I think we've saved about 10% from last years cost already.

That's not driven primarily by reducing the day rate, but by drilling more wells per day essentially.

So I think the productivity gains should more than offset whatever modest inflation there is in the cost.

Okay, that's helpful for sure.

And can you guys 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 the -- I reiterate this morning that we're still looking at options for the Piceance and Williston Basin.

Maybe a little more activity in one of those.

We don't know yet.

And we also said that varied in the comments was that if we can get the right arrangement perhaps some of the -- Midstream assets 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.

That's helpful.

Ryan Todd of Deutsche Bank.

Great, thanks.

If I could ask 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?

Have you drilled 2-mile laterals or are you extending the lateral length?

And if so how much of your acreage there in the basin do you think would be conducive to longer laterals?

Currently in the Delaware Basin, we're drilling lateral lengths of between 3,300 feet and 4,200 feet.

What we're doing right now is some modeling with respect to the optimum lateral lengths in the basin.

As you know, the Wolfcamp productivity in the Texas Delaware is much better than in the Midland basin.

And thus far, we're seeing some good productivities from the lateral lengths that we're drilling.

We haven't really drilled much yet over 4,200 feet.

Two of the challenges there are as I said at what point do you -- have you drilled so much that you start destroying value?

In terms of the just the friction effects of the longer laterals.

And the other thing is that you have the challenges of the acreage positions with respect to ensuring that you've set up your opportunities to go with the longer laterals.

Currently, we're seeing that probably it's more likely to leave 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.

Maybe a little different focus than some other people.

I think we focus on our finding cost calculation rather than the IP calculation.

So from our perspective, to lengthen the laterals may cost us more money.

You might get more IP but maybe at a cost of a higher finding cost.

It's not the way we think about things.

A small producer may be more interested in IPs.

That's helpful.

Have you seen, still in the Delaware, what are you seeing from a Oil and Gas mix in your Wolfcamp wells there?

And are you seeing much variation across the extent of your acreage?

We're seeing a little bit of variation but typically we're seeing anywhere from 72% to 80% oil in the Texas Delaware.

And in most cases we're seeing above 75%.

We're a little pickier or maybe we have better acreage than some other people who are doing a fair amount and get gassier results.

Okay.

You can see that our oil is rising and our gas isn't if you look at the numbers we've given you.

We're basically a little pickier than some other people who maybe that's all they've got is they're drilling gassier wells.

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 governing factors on the potential to show upside over that three year window?

We think on the production numbers we've given we have considerable upside just with the drilling we're showing.

But putting that aside, it's a return base business and we'd just as soon let other people make mistakes and learn from that before we expand our footprint a lot.

But there's also other logistical issues in the basin.

We want to make sure that we have takeaway capacity for the oil.

I'm more concerned frankly, about takeaway capacity for gas.

You're not going to be able to flare the gas and the gas production in the basin is likely to grow sharply in the next year or two as people drill these gassier wells.

And so 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.

Thanks, I appreciate the help.

I'll leave it there.

Thank you.

Jason Gammel of 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 the last quarter you have about a 20 year inventory.

Obviously, doubling the rig count will take that back to a 10 year inventory.

But I also assume you're going to be adding locations over time.

So how do actually then balance the amount of drilling inventory that you have from an MPV basis?

And what I'm really getting more broadly, do you see divestiture opportunities within the Permian Basin as well as special acquisitions?

If I look at the list of mistakes I've made over the last 20 years, the mistake I've made most is divesting anything in the Permian Basin.

And because with so many horizons, there's so much there, there so much oil available in the system, so we didn't divest that much but I regret every acre.

So I think that while I'm here, we're not going to be divesting anything.

I think the program that Vicki's outlined is sort of the minimum program.

That's what we think we could achieve over the next couple of years without wasting money.

As we get better at this and the basin matures, there'll be more opportunities because we're 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.

We are in pretty good shape for that.

And we do control 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 spinout process.

It looks to me and maybe I've just missed something but I think that you're estimate on the amount of shares that you'll be able to repurchase from the transaction went to 60 million from a range of 40 million to 50 million.

My question is, is this going to be related to just under 20% retention of equity and the exchange over time and do you still expect to take a $5 billion dividend out?

No.

Dividend is $6 billion.

Okay.

We haven't counted the shares in the exchange.

So it simply our -- we got our modelers out and so they divided $6 billion by $100 and came up with 60 million shares.

We didn't pay a lot for that advice.

Very good.

I think I understand now.

Okay, thank you.

Paul Sankey of Wolfe Research.

Hello, everyone and congratulations to those of you who have new roles.

I didn't understand Steve, that last point believe it or not.

The exchange offer has to be completed within 18 months, and any proceeds from that, I guess is the word, would be used for buyback -- additional buyback?

No, it's actually -- just so you understand that the shares, the 19.9% shares that we own, our options are limited because it is 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.

We can do that without paying any tax.

In theory, if we handed that kind of debt around we'd exchange it for debt but there isn't that much debt around to do that.

If we do any -- the third alternative would be simply distribute the shares to the shareholders if we couldn't do that.

That also would be tax-free.

If we sold it for money, we would have to pay tax on it.

So our preference would be to do the exchange offer.

So basically, it's a split off of the 19.9% in terms.

I think those are -- what we did was we guessed at how much it might -- we have included that number in our 60 million shares.

But there will be some number of shares that we'll exchange the CRC shares for Oxy shares and we do that without paying any tax.

Okay.

And the follow, on slide which is 21 where you showed that the same as 60 million.

It says clearly you don't include anything from MENA.

I just wonder why it says it did not reflect debt reduction?

Does that mean you're going to pay down debt as well?

Well there's a small amount of debt reduction probably.

It's just in a rounding.

I figured.

I just wanted to confirm that.

So the fact that your list of mistakes made me think of Lindsey Lohan actually, funny enough.

Would that involve you potentially making an acquisition in the Permian, further acquisitions of scale?

Thanks.

The answer to the Permian acquisition 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 6, 7 times where we want to save a cash flow and the acquisitions are very dilutive and I can't imagine doing one.

I suppose if there's a collapse in oil price or something like that, that would be a different story but absent a huge reduction in the public market values of these companies, I can't even imagine doing one.

Hopefully my successors are well-trained enough not to do anything stupid, too.

Thank you.

And then finally for me, in the past you've openly debated the buyback as 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?

And I'll leave it there.

No.

Hopefully it won't be a stupid process.

I think that's what you are -- blind is another word for stupid.

I think you've said in the past that there's a fair value --

There's a fair value we believe in, and we'll do what we -- yes, we're going to buy back the shares ultimately but it also depends on the price.

We would expect that during the process of divesting of the California Company, the stock will -- during the confusion will trade at -- the Oxy stock will trade at some, what we would view as a discounted value.

And we would expect that we could buy a lot of shares during that period.

I'd be pleased to be wrong, but that would be a reasonable expectation during that period.

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

As opposed to buyback.

More, but not materially more I think is the answer.

Could you put another $1 billion dollars to work?

Yes.

Could you put $2 billion to work?

Maybe.

$3 billion to work?

No.

I think we've 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.

Thanks very much Steve.

Thanks.

Ed Westlake of Credit Suisse.

Yes, 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 still going to have the same ratio?

Help us understand how many vertical rigs will be in that 47 plus seven?

I don't see us having more than about six or seven vertical rigs at any given time in the future so the bulk of the 47 to 54 that we'll have, I would expect only about six or seven of those to be vertical.

Obviously, you've given us a 7,000 locations and Jason was probing on that but as you ramp up the rigs, your inventory is going to drop I think perhaps a little bit faster.

So at least on a forward-looking basis when we get to 2016 which is obviously a bit further in the future, where would you then go next after the initial inventory?

It seems like you've got some good sweet spots in the Midland and fantastic sweet spot in the Texas Delaware.

Feels like a lot of your equity is over in the Bone Springs, so talk about how the returns would change as you shifted those rigs around through the program.

Let me say that 7,000 is based on the appraisal work in the evaluations we have done to-date.

We fully expect that 7,000 to grow.

As you know we have a huge acreage position and what we're trying to do is go through our initial step of exploration and then appraisal before we're adding -- some appraisal work has to be done before we add locations to our current inventory.

So I'm almost thinking with what we're seeing I wouldn't be surprised to see that our inventory increases by the amount of wells that we drill.

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 areas so that we can make sure that we accelerate efficiently.

And then we're also limiting our appraisal areas too, to make sure that we go in, we get our appraisal work done and then we transition to development mode.

Some appraisal work, there is some areas where we haven't even begun our appraisal work.

And then just a question on the Midstream.

I know you've 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?

Yes, I think you have to split the revenue streams that come out of this into two.

One is the tariff streams.

And those are -- once you build the pipeline they're not very interesting.

And the other is the trading or streams our ability to move the oil at 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, we've got plenty for us, we're three times what we currently produce.

We've got plenty for us.

We'll see how it goes.

Again, I'm focused about putting the Midstream money right now in the move in 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.

We're focused on making sure that -- by building this stuff out, we've made it better for everybody in the basin.

And then on the gas we expect to do the same thing.

A final question, you've seen the -- these royalty interest, mineral interest streams start to get traded independently of the companies.

Maybe just a reminder of where your royalty position is in some of your legacy acreage.

It's a complicated number.

To put it mildly.

First of all, the king of this royalty stuff is in the California business.

So you probably can ask them about it when they show up.

But putting that aside, we -- there's royalties let's say under one of our EOR fields that we own the royalty interest there or a large piece of the royalty interest.

So if we were 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.

And we don't really know the number at this point.

It's not -- they're counting the checks to try to figure it out.

But for the -- excluding California, the royalty income is somewhere in the range of $300 million a year and we just have to root through it and figure it out.

I think where it doesn't affect our ability to manage our base business because our royalties are scattered in a number of places.

Somebody would like to pay 15 times cash flow, I think we're game.

On the other hand, where it affects our base business we just as soon keep it because I think it'll hurt us in our finding cost going forward.

Thanks, very clear and helpful.

Thank you.

John Herrlin of Societe Generale.

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 --

And as you know, we do a lot of pad drilling elsewhere so it's not like we are 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 think you have enough people?

We're adding people.

We're ramping up and we are going to have to add a few more people to our Permian resources and exploitation teams and our field execution teams.

But so far we've been able to add the people that we need as we progress.

Okay, great.

Last one for me, Steve.

You talked about addressing the Midstream.

Does this mean MLP or just outright sale?

It doesn't.

If somebody would give you 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 can 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.

Hello, thank you everyone for listening.

I know its been a busy day for you all.

We'll be available in New York for your questions.

Thanks.

The conference is now concluded.

Thank you for attending today's presentation.

You may now disconnect.