西方石油 (OXY) 2013 Q4 法說會逐字稿

Good morning and welcome to the Occidental Petroleum Corporation fourth quarter 2013 earnings conference call.

All participants will be in a listen-only mode.

(Operator Instructions)

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

Please go ahead.

Thank you, Emily, and good morning, everyone.

Thanks for participating in Occidental Petroleum's fourth quarter 2013 earnings conference call.

On the call with us this morning from Houston are Steve Chazen, Oxy's President and Chief Executive Officer; Vicki Hollub, Executive Vice President of Oxy's US Oil and Gas Operations; Cynthia Walker, our Chief Financial Officer; Willie Chiang, Oxy's Vice President of Operations and head of our Midstream business; Bill Albrecht, President of Oxy's Oil and Gas in the Americas and Sandy Lowe, President of our International Oil and Gas Operations.

We're going to change things up a bit this quarter and begin the call with comments from our CEO Steve Chazen who will review some of the achievements we realized last year with respect to the fundamentals of our business and our strategy and plan for 2014.

Vicki Hollub will then provide a thorough discussion on the strategy and outlook for our operations in both the Permian Basin and California.

In order to provide a little more time for discussion around our domestic oil and gas operations, we will not directly address our fourth-quarter results on the call.

However, Cynthia Walker's detailed commentary on the fourth quarter, as well as forward-looking guidance items, can be found in the conference call slides sent to you following Vicki's remarks and beginning with slide 46.

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 the risks and uncertainties that may cause actual results to differ from those expressed or implied in these statements and our filings.

Our fourth-quarter 2013 earnings press release, the Investor Relations supplemental schedules, conference call presentation slides, as well as Cynthia's detailed commentary on the fourth quarter results have been posted and can be downloaded off of our website at www.oxy.com.

I will now turn the call over to Steve Chazen.

Steve, please go ahead.

Thank you, Chris.

We just finished a successful year meeting or succeeding many of the goals we set out for ourselves and are looking to continue our performance into 2014.

Let me give you a brief overview of the key 2013 highlights.

We grew our domestic oil production by 11,000 barrels per day over 2012 to 266,000 a day.

We exceeded our capital efficiency goals, reducing our drilling costs by 24% from the 2012 levels, reduced domestic operating costs by 17%.

We added about 470 million barrels of reserve equivalents, achieving an overall replacement ratio of 169%.

Our total costs incurred associated with those reserve adds were about $7.7 billion, resulting in an apparent finding and development cost of under $17.

We increased our return on capital employed from 10.3% in 2012 to 12.2% in 2013.

Turning now to some of the specifics of the key accomplishments of last year.

As a result of our development program, we improved our capital efficiency by 24% domestically over 2012, which translates to about a $900 million reduction in capital for the wells drilled in 2013.

Of this improvement 50% came from the Permian Basin, 25% from California and 25% from the rest of the domestic assets.

We accomplished these improvements while successfully competing our program by drilling approximately what we had planned.

We also reduced our domestic operating costs by 17%, or about $470 million, compared to 2012.

About 48% of this improvement was Permian Basin, 46% was in California and the remainder was in the other domestic assets.

While we focused on these efficiencies we also grew our domestic oil production by 11,000 barrels a day.

With respect to reserves, we had a very successful year in growing the Company's reserve base by adding substantially more reserves than we produced, over 90% of which was added through organic development program.

We ended the year based on a preliminary estimate with about 3.5 billion barrels of reserves which represent an all-time high for the Company.

Our total Company reserve replacement ratio from all categories before disposition was about 169%, or about 479 million barrels of new reserves compared to 278 million barrels we produced during the year.

In the United States our reserve replacement ratio was 190%.

Replacement ratios to California properties in the Permian non-CO2 properties were similar to the overall ratio.

Our reserve replacement ratio for liquids from all categories was 195% for the total Company and 228% domestically.

This reflects our emphasis in oil drilling instead of gas.

Our total costs incurred related to total reserve additions for the year on a preliminary basis were about $7.7 billion.

Over the last several years we have built a large portfolio of growth-oriented assets in the United States.

In 2013 we spent larger than normal portion of our investment dollars in development of these assets.

Our organic reserve replacement for the year reflects the positive results of these development efforts.

Our 2013 program, excluding acquisitions, replaced 168% of our domestic production with about 291 million barrels of reserves adds.

In addition we transferred 115 million barrels approved undeveloped that proved developed category domestically as a result of the program.

Our acquisitions were at a multi-year low of $550 million, providing reserve adds of 32 million barrels.

At the end of the year we estimate that 73% of our total prove reserves were liquids, increasing from 72% in 2012.

Of the total reserves about 70% were proved developed compared to 73% last year, 2012, that is.

The increase in the share of the proved undeveloped reserves compared to last year was the result of reserves added at the Al Hosn Gas Project.

We expect to move these reserves to proved developed category at the end of this year, once the initial production starts in the fourth quarter.

Through the success of our drilling program and capital efficiency initiative, we lowered our finding and development costs over recent years.

As a result, we expect our DD&A expense to be around $17.40 a barrel, only a small increase from the $17.10 in 2013.

This is consistent with our expectation the DD&A rate of growth should flatten out as recent investments come online and finding and development cost come down.

Success of our organic reserve additions and the efficiencies we have achieved in our operations, demonstrates the significant process we have made in turning the Company into a competitive domestic producer.

One of our long-term goals domestically has been to achieve a 50% pre-tax margin after finding and development and cash operating costs so as to generate solid returns.

We believe we are achieving that now and expect to continue to do so in the future.

Consistent with what we have said, our focus in 2013 was to enhance shareholder value through our results.

For this goal our program was heavily focused on growing our domestic oil production, improving our capital efficiency, that is, improving our finding and development costs and lowering our operating costs.

We met or exceeded these goals and result have increased our return on capital to 12.2%, a significant improvement from the 10.3% of last year.

That testament to the hard work and dedication of all of our employees.

We expect to see further improvements in our returns in coming years as a result of recent investments.

Turning to this year, our 2014 program is designed to improve upon last year's strong performance.

Let me highlight the key elements of the 2014 program, which I will discuss without reflecting any of the effects of our strategic review initiatives.

We expect our 2014 program to be about $10.2 billion, compared to the $8.8 billion we spent in 2013.

The increase includes about $400 million of additional capital allocated to each of our California and Permian operations, largely for additional drilling to accelerate their development plans and production growth.

An additional $100 million will be spent in these and other domestic assets for facilities projects that were deferred from 2013.

The domestic oil and gas capital program will continue to focus on growing oil production and the entire increase in capital will go to oil projects in California and the Permian Basin.

We also expect to continue to find growth opportunities in our key international assets, mainly in Oman and Qatar, and complete the Al Hosn Gas Project.

Our capital for 2014 for Oman and Qatar will increase by about $300 million over last year.

Our exploration capital will increase by about $100 million, in part due to spending that was deferred from last year.

Our midstream capital increased by about $100 million as result of spending on the BridgeTex pipeline and two new terminals at Ingleside.

Our chemical capital increased also by about $100 million due to the Mexican joint venture we announced last year while we complete the new Johnsonville chlor-alkali facility.

Our success in improving our capital efficiency and operating cost structure has provided us with the ability to expand our development opportunities that met our financial return targets.

The capital program production growth that outlined that reflects the benefit of our streamlined structure and our commitment to continue to fuel growth by exploiting our large portfolio, primarily in California and in the Permian Basin.

With the expect to our 2014 production, we expect our Company-wide production volume to grow to between 780,000 and 790,000-barrel equivalents a day, compared to 763,000 in 2013, with a fourth quarter exit rate of over 800,000 barrels a day, excluding the planned Al Hosn production.

This increase will come almost entirely from domestic oil production while we expect to see a continued modest drop in our domestic gas volumes.

Our domestic oil production is expected to grow from 266,000 barrels a day in 2013 to between 280,000 and 295,000 barrels a day in 2014, or about a 9% increase.

This growth will come fairly evenly from our California and Permian operations.

Internationally, excluding Al Hosn, we expect production to grow slightly.

While the elements in 2014 program that I discussed assumes no changes to company structure or its mix of assets, we do expect the Company to look significantly different by the end of the year.

Strategic fuel we are undertaking will result in large changes to the Company's asset mix.

Our capital program and production expectations and other elements in the 2014 program will be adjusted as the related transactions are concluded.

Finally, some of our longer lead investments we have been making over the last couple of years will start contributing to our results this year.

Specifically, the Al Hosn Gas Project.

We expect to start its initial production in the fourth quarter and start contributing to our cash flow.

We expect the BridgeTex pipeline to come online around the third quarter and to start contributing to our midstream earnings and cash flow.

The new Johnsonville chlor-alkali plant is expected to come online early this year and will make a positive contribution to the operations for our chemical business.

With respect to the initiatives outlined in the first phase of the Company's strategic review announced last year, we completed a sale of a portion of the Company's investment in the general partner Plains All-American pipeline in October, resulting in pre-tax proceeds of about $1.4 billion.

After the sale, we continued to own about a 25% interest in the Plains general partner, which at current market price is to be valued at about $4 billion.

We have made steady progress in our discussions with key partners in the countries where we operate in the MENA region for the sale of our minority interest in our operations there.

Due to the scale and complexities of potential transaction, we expect these discussions to continue through the first half of this year.

We have made good progress in the pursuit of strategic alternatives to the select MidCon assets.

We expect to provide further information on any transactions as they conclude somewhere around the end of the second quarter.

And we'll announce material developments as they occur.

In the fourth quarter we used the Plains proceeds to retire $625 million of debt, reducing our debt load by about 9%, and to purchase almost 10 million shares of the Company's stock with a cash outlay of $880 million.

We ended the year with a debt-to-capitalization ratio of 14%.

At the February board meeting we will review the Company's dividend policy, status of strategic alternatives and share repurchase authority.

Many of the steps we've taken in 2013, including our success in improving our efficiency and the actions that our board has authorized, lay a groundwork for stronger results for this year and beyond.

The operational improvements we expect to achieve in 2014, coupled with the strategic accident we expect to execute this year, should place the Company in a position to improve its returns while continuing to grow and increase its dividends to maximize shareholder value.

Vicki Hollub will now provide a more detailed discussion of our California and Permian operations.

Thank you, Steve.

This morning I'll review two of our largest domestic operations, our Permian and California businesses, describing our 2014 plans as well as longer-term growth opportunities.

In 2013 we implemented an important transition plan in both of these businesses and the success we achieved built a solid foundation for long-term growth.

In 2014 the specific goals of our operations are continued development of our large anchor projects in each of our operating areas, which will enable us to allocate a significant portion of our capital to projects with solid returns, low execution risk and long-term growth.

Further reduce our drilling and completion costs to improve our finding and development cost and our project economics, continue to optimize operating cost without affecting production to improve our current earnings and free cash flow, build out our successful exploration efforts in each of our core areas, evaluate data and test various new concepts in our pilot areas which will set up the anchor projects for the future.

We manage our Permian basin operation through two business units, the Permian EOR business, which combines CO2 and waterfloods, and the Permian Resources business, which is where our growth-oriented and unconventional opportunities are managed.

I will refer to the CO2 and waterflood business as Permian EOR and the other business as Permian Resources.

The Permian Basin designation will be for the combined operations.

In the Permian Basin we spent over $1.7 billion of capital in 2013, with 64% focused on our Permian Resources assets.

In 2014 we plan to spend just under $2.2 billion overall on the basin.

The entire $450 million increase will be spent on our Permian resources assets representing about 70% of our total capital spend in the basin.

We expect the Permian EOR business to offset its decline in 2014 and to actually grow 1.4%.

The Permian Resources oil production is expected to grow faster at a range of 20% to 25% and its total production by 13% to 16%.

On a combined basis for the Permian Basin, this should translate oil production growth of over 6% in 2014 and total overall production growth of over 5% while generating $1.8 billion of cash flow after capital.

2013 was a pivotal year for our Permian Basin operations.

First, we improved capital efficiency by 25% and reduced our operating expenses by $3.22 a barrel, or 17%.

We also began transitioning to a horizontal drilling program.

We drilled 49 horizontal wells with 47 completed and producing.

The combination of improvements in well cost, our own results and those of neighboring operators have given us the opportunity to dramatically shift our program to more horizontal drilling in 2014.

Our Permian Resources team will average running about 21 rigs, of which 17 will be drilling horizontal wells.

We plan to drill approximately 345 total wells, or about 50%, of which will be horizontal.

This compares to 330 total wells drilled in 2013 where only 15% were horizontal.

We have two main goals for our Permian Resources business in 2014.

First we intend to continue to evaluation of the potential across our full acreage position.

And second we plan to pilot various development strategies, including optimal lateral length, frac design and well spacing, both laterally and vertically.

We believe this will position us for accelerated development as we exit 2014 and go into 2015.

We believe we have one of the most promising and under-exploited unconventional portfolios in the basin.

In 2013 we added 200,000 net perspective acres to our unconventional portfolios and now have about 1.9 million prospective acres.

This is a prime position in the Permian Basin.

Our acreage in the Midland Basin, Texas Delaware Basin and New Mexico gives us exposure to all unconventional plays, which is unique.

This will give us flexibility to develop our most attractive opportunities first and to mitigate risk.

Based on the work we've done to date, we have identified approximately 4,500 drilling locations across our portfolio, representing 1.2 billion net barrels of resource potential.

We believe we've made concerted assumptions regarding prospective acres, well spacing and expected ultimate recoveries and expect these numbers will grow as we learn more.

We see the largest near-term growth in the Midland Basin, which represents about two-thirds of our currently assessed resource potential.

However, our Delaware Basin prospective acreage is significantly larger and potentially there should be room to grow.

We continue -- we believe our measured approach to our unconventional portfolio has worked to our advantage.

Our Permian Resources production comes from about 9,500 gross wells of which 54% are operated by other producers.

On a net basis, we have approximately 4,400 wells of which 15% are non-operated.

This has given us the opportunity to observe the results achieved by other operators in the basin, learn from those results and optimize our approach to maximize the opportunities on our acreage.

The success of our capital and operating cost efficiency efforts in 2013 has enabled us to significantly improve our cost structure, which has increased our opportunity set.

For example, a typical well in the Collie area that had an IRR of 24% before our capital and operating cost reductions now yields IRR of 48% using the same product prices.

We achieved similar success in all of our most active areas across the business unit.

Finally, we have established a multi-step, methodical process for our unconventional acreage in the Permian Resources business that includes; step one, exploration to establish the presence of a commercial resource; step two, testing and data gathering to optimize well and completion design; step three, pilot programs to assess variability of well performance to design full field development plans; and step four, transition to manufacturing mode for full field development.

This process is helping us prudently develop our acreage, maximizing cash flow and returns.

As a result, we are now prepared to accelerate our activities in the Permian Resources business, where believe the opportunity in front of us is one of the biggest in the basin.

Now I'll review our program in more detail, beginning with the Midland Basin.

We've been most active with our horizontal activity to date in Midland Basin, where we've drilled 16 wells.

In 2014 we plan to spend $790 million to drill 147 wells, including 74 horizontals.

We expect to average eight rigs in the area during this year.

Our largest opportunity here is in the Wolfcamp Shale, where we've tested Wolfcamp A and B benches and plan to target our activity to test the remaining benches.

One of our most successful pilot projects in this basin is South Curtis Ranch, which has now gone into full field development mode.

This is a property that we acquired in 2010.

We've drilled 63 vertical and 6 horizontal wells to date and plan to drill over 200 additional wells on this acreage.

Results thus far have been as expected with initial 30-day production rates for the horizontal wells averaging approximately 800 BOE per day.

In the Midland Basin we also believe there is substantial potential in the Cline, which is currently under evaluation.

We've drilled six horizontal Cline wells so far and plan to drill another 5 to 10 in 2014.

Preliminary results indicate we may have the opportunity to drill up to 450 Cline wells in the basin.

Another pilot project is horizontal drilling in the Sprayberry, where we plan to drill our first horizontal well in first quarter and will evaluate next steps with the results.

In addition to the horizontal activity, we also plan to continue our legacy vertical Wolfberry development.

In the Texas Delaware Basin we plan to spend approximately $370 million in 2014 to drill 91 wells, including 48 horizontals.

We expect to average five rigs during the year.

And our horizontal activity will be focused in the Wolfcamp, where we believe the A, B and C benches will prove to be the most perspective.

We drilled or participated in 3 horizontal Wolfcamp wells in 2013 and will increase that to 45 in 2014.

Our activity is centered in Reeves County where we historically have drilled vertical Wolfbone wells.

Early horizontal results are proving to have better economics, but there are some plays where vertical development is still more efficient.

In our Collie area we plan to drill 43 vertical wells, targeting the Bell and Cherry Canyon formations, which represents a continuation of the one rig program we executed in 2013.

In New Mexico we plan to spend approximately $370 million to drill 97 wells, including 50 horizontals.

We expect to average four rigs during the year.

The Bone Spring formation in New Mexico is the second largest opportunity in our portfolio behind the Wolfcamp Shale.

In 2013 we drilled 16 horizontal wells, testing the first, second and third Bone Spring sand intervals.

Our results were very encouraging and we expect to increase the program to drill 30 horizontal Bone Spring sand wells in 2014.

Of the $2.2 billion to be spent in Permian Basin in 2014, $660 million will be allocated to our Permian EOR business.

As I previously mentioned, this business unit is a combination of CO2 and waterfloods.

It is symbiotic to manage these assets together as they have similar development characteristics and ongoing monitoring and maintenance requirements.

The last couple of years we have actually spent more capital on waterfloods as we mature the next CO2 developments.

In 2014, 25% of the $660 million will be spent on current waterflood development and the remainder on CO2 floods.

Further, we have 1.4 billion net barrels of oil equivalent in reserves and potential resources remaining to be developed in the Permian EOR business.

We believe we are the efficiency leader in the basin in applying CO2 flood technology to develop this potential.

We have the ability to accelerate growth in our EOR projects as more CO2 becomes available.

As a result of our efficiency advantage, many projects that don't work for others work for us.

Over the last several years the focus of our Permian exploration program has been to identify unconventional opportunities which are then transitioned to full field development through the process I explained earlier.

Our approach has been very successful, giving us a large opportunity set that we are now working to fully develop.

We continue to see the addition of new plays in the basin as the years of exploration drilling opportunities ahead in our 2 million in prospective acre position.

Now that I've gone through some of the specifics of the program for the Permian Basin, I will explain our overall business strategy.

We are approaching our development program with a multi-pronged strategy that first, maximizes the field resource potential; second, controls cost to optimize returns; third, gives us a strategic advantage to improve our realizations.

We are using targeted horizontal and vertical drilling as appropriate, optimizing development and completion plans from lateral length to frac efficiencies as well as lift strategies to maximize recovery.

We are making heavier infrastructure investments like power, water handling and gas processing to pre-plan for life and field success.

These strategies, coupled with our successful exploration program, accomplish the first of our objectives.

We will continue to manage costs and take advantage of our progress along the learning curve with leading technologies and execution efficiencies to accomplish our second objective.

And we are also investing in additional take-away capacity, including the completion of the BridgeTex pipeline and build-out of our gathering systems, which will give our crude a strategic advantage to reach either Houston Ship Channel or Corpus Christi markets.

Finally, I would like to comment on our plans for the Permian Basin over the next several years.

With the combined businesses, we have more than 2.5 billion barrels of oil equivalent in reserves and potential resources.

Within each business, we have the flexibility to shift capital among projects within that business, as well as the flexibility to shift capital between the two businesses as needed.

Our large and diverse portfolio creates opportunities for a variety of growth options.

In the Permian Resources business, at our current pace we believe we have over 15 years of development and growth opportunities.

Given that the Permian EOR business is generating significant cash flow and we expect our opportunity set to continue to grow, we plan to double our rigs over the next three years to accelerate the development of the Permian Resources unit's growth opportunities.

We expect this to result in the doubling of our resources units production from approximately 64,000 BOE per day in 2013 to more than 120,000 in 2016.

In Permian EOR, while it is large with a somewhat slower growth curve, we have significant opportunities going forward with continued positive cash flow to fuel the growth of the resources unit.

Combined with EOR growth opportunities, we expect our overall Permian Basin production to grow by roughly 10% compounded annually growth rate through 2016.

Now I will shift to California.

In 2013 we spent $1.5 billion of capital.

Our main goals were to deliver predictable outcome, advanced low-risk projects that contribute to long-term growth, reduce the cost structure, lower our base decline, create a more balanced portfolio and test exploration and development concepts.

We achieved every one of these objectives.

We produced 154,000 barrels of oil equivalent per day, generated $1.3 billion of free cash flow after capital.

We progressed the development of our seam plugs and current front in Lost Hills and started the redevelopment of our Huntington Beach field.

We improved our capital efficiency by 20% versus 2012 and also reduced operating costs by $4.70 per BOE, or 20%.

Overall in 2014, we intend to continue the capital strategy shift initiated last year, which was to focus the majority of our capital on low decline projects.

Our goals for this year are to accelerate the rate of production growth and maintain our lower cost structure.

We will also continue to advance several low-risk, high-return, long-term growth projects and capitalize on exploration successes.

In 2014 we plan to spend $1.9 billion of capital, of which 40% will be spent on waterfloods, 20% on steam floods and 40% on unconventional and other developing plays.

We expect to average about 27 rigs in California in 2014, compared to an average of 20 rigs in 2013.

We plan to drill around 1,050 wells in 2014 compared to 770 in 2013.

We expect this program to deliver around 11% oil production growth, or over 4% total production growth, while generating $1 billion of free cash flow after capital via current prices.

We believe the rate of growth will further accelerate in 2015 and beyond as a number of the steam and waterflood projects reach full production and the base decline is lower due to relatively less natural gas development, higher investment and lower decline oil projects and a larger share of higher growth, lower decline project in the asset mix.

Let me now share some of the highlights of the program for this year, beginning with the waterfloods.

In the LA Basin we plan to spend $500 million in the Wilmington and Huntington Beach fields.

Our Wilmington field development in 2013 exceeded expectations.

We drilled 135 wells and will increase that by 7% to 145 wells in 2014.

Our horizontal program was particularly strong and horizontal wells will represent an even greater percentage of wells in 2014.

In our Huntington Beach redevelopment we successfully brought online our two new for-purpose drilling rigs and drilled and completed our first two wells in the project.

In 2014 we plan to drill 30 wells and will ultimately drill at least 128 wells.

Our heavy oil business unit was the key focus area in 2014 and will be again in 2014.

We plan to spend $350 million to drill about 420 wells, compared to 324 wells in 2013.

We'll also continue the multi-year development of the current front and Lost Hills steam floods and will pilot some new projects.

I would also like to highlight that the business achieved record production in the fourth quarter, producing 19,000 BOE per day, which is an increase of 4,000 barrels per day from the first quarter of 2013.

At Elk Hills our key objective is to lower the high decline rate and we have made significant progress towards this goal.

In 2014 we plan to spend $600 million in capital to drill 325 wells, which is an increase of $170 million over 2013.

About 55% of Elk Hills capital will be targeting our shale reservoirs where our capital efficiency efforts in 2013 had a significant impact.

We experienced an average of 23% decline in well costs for these programs and 21% decline in operating costs, which dramatically improved the economics and then increased the opportunity set.

For example, a typical well that generated 30% IRR prior to efficiency initiatives now delivers 50% IRR using the same product prices.

In 2014 we will drill around 130 shale wells at Elk Hills, an increase from 80 in 2013.

The remaining Elk Hills capital will target continued development in the shallow oil zone and Stephen stand.

Our California exploration program has delivered solid results for over five years.

The 2014 California program will continue to explore both unconventional and conventional targets.

The unconventional program targets several prospects similar to the 2013 discovery.

The conventional program will target prospects in and around our existing production in both the San Joaquin Valley and Ventura County.

Our extensive proprietary treaty seismic surveys are yielding an exciting inventory of leads and prospects, which will provide years of drilling opportunities.

Lastly, I would like to give you some perspectives on our developmental plans over the next several years in California.

We expect to continue the capital strategy we initiated in 2013, the shift to lower decline and lower risk steam and waterflood projects.

We believe we can grow our California production from 154,000 barrels of oil equivalent per day currently to 190,000 in 2016, while roughly a 7.5% compounded annual growth rate.

Our steam and waterflood projects will contribute 80% of that growth.

In fact, 90% will come from projects that are already online.

We believe -- we think this positions California as one of the lowest risk growth profiles in the industry.

Further, we are targeting primarily oil drilling, which will make our portfolio more oily, contributing to solid margin expansion going forward.

We expect to grow our oil volumes by roughly up 15% compounded annual growth rate through 2016.

Over the long-term we expect our California growth prospects to benefit from changes in our asset mix.

Elk Hills and Thumbs, while having the potential for years of continued production, have lower growth prospects due to the mature state of both of these fields.

On the other hand, our water and steam floods, as well as our unconventional opportunities, should continue to give us double-digit growth for years to come.

A share of our production from Elk Hills and Thumbs has shrunk from 64% in 2009 to 44% in 2013.

This shift will continue going forward and the larger share of higher growth projects will further accelerate the growth rate in coming years.

As in the Permian Basin, we are continuing to test new ideas and to further improve our drilling completion and development efficiency in all of our projects.

We're also working diligently to comply with the new regulatory requirements created as a result of the passage of Senate Bill 4 in California.

We have a dedicated team addressing the associated issues and currently we don't expect significant delays in our development plans.

As you can see, while the Permian Basin and California stories are different, they're both very exciting.

The hard work and dedication of our people have put both of these assets in a position for continued success and 2014 is the year that both of these businesses will begin to accelerate their growth as we have completed the transition to a focused, growth-oriented development program and we're set for long-term growth.

I will now turn the call back to Chris Stavros.

Thanks, Vicki.

Emily, can you please open the line for questions?

We're ready to take questions.

Thanks.

(Operator Instructions).

Doug Terreson, ISI.

Good morning, everybody.

Steve, Oxy's returns on capital rose last year by almost 20%, which I think was the objective or hope anyway.

But your capital spending looks like it's going to rise by another 16% or so this year.

My question, how does management prevent capital misallocation and then prevent it from occurring again as it did a couple of years ago, meaning have there been changes to the capital allocation process or in other areas of corporate planning that might enhance the result in the current scenario?

Sure.

Thank you.

First remember that this number is for an unchanged business.

And that is really not going to happen.

So the actual spending will be some other number, a lower number because some businesses won't be here by year-end.

Right.

We've changed the process.

I think Vicki has pointed out the change in the domestic business, and how we are focusing on returns a lot better and we are not -- I would say basically a lower risk portfolio and we'll generate more certain returns.

We expect the returns -- we are not actually excited about the 12% return on capital deploy.

I think we need to be closer in excess of 15%.

Our goal is to make sure that is right.

It's with very great caution on my part that I have allowed additional spending in the Permian and California.

They've had to convince that are going to stay on the straight and narrow here, so I am pretty sure we are under control, but if it turns out, because we can watch this monthly, that's what we do now, watch it monthly.

If it turns out they get off the wagon, the beer will be turned off.

(laughter) One more question, you guys --.

Or the fine wine or whatever they are drinking.

One of the two.

You guys were obviously very successful with your cost program.

That helped the result last year.

So, are we mostly complete, is their more work to do there on the cost program?

For sure.

I think we exceeded our goals.

We will set new goals.

I think my main focus, just so we are real clear, the long-term business depends on low F&D.

Operating costs are fun because they affect the current year, but we have to develop a long-term low F&D rate.

Go back to what we said forever.

If we add the F&D and the operating costs and the local taxes, we need to be below 50% of the selling price of the product.

If you can do that, you'll have pre-tax margins of 50%, and you will generate good returns.

And that is really the objective.

So we need to continue to drive -- as the reservoirs become more challenging, we need to -- our costs need to be watched very carefully.

I think we have used this year, 2013 that is, to really hone our ability to control costs.

I think we are there.

We have gone through multi-year transition of the Company from a very good international producer and an okay domestic one, to a much stronger domestic business.

This has not been an easy or quick transition, but I think at this point we have the people in place to accomplish those goals going forward.

We are giving them more money this year, but I hold myself and them responsible, unlike football teams.

The coach gets fired, not the assistant coaches in this.

(laughter).

Well, if you guys can make 15% returns on capital that would be fantastic.

I think we'll be there.

Great, thanks.

Doug Leggate, Bank of America Merrill Lynch.

Thanks, good morning, Steve.

Welcome to Houston, I guess.

I have a couple also if I may.

California is, I guess, judged to some extent as not being able to execute because of a lack of visibility.

You have laid out some targets this morning, obviously, that suggest a step-up in activity, but what comfort can you give that you have got the permits and you have got the rig count.

I'm just curious as to where you're head is in terms of whether or not separating California is still viable option and one you think would benefit the balance of the portfolio?

And I've got a follow up, please?

I will answer the last question first, and then we will let Vicki, the assistant coach here, get ready to answer how certain she is.

California and the Permian, and the rest of the Company, are quite -- in some ways different businesses.

California can benefit a lot, I think.

My higher capital spending, and it will generate more growth.

We established a base with, you might call it boring if you want, steam flood and those kind of projects so they'll, I will, have enough cash flow to go ahead.

I think it could be managed differently then we would.

I think it has good prospects.

I think the issue -- we need to have a team together that is more aggressive growers, maybe less concerned about dividends.

And look more like a small E&P.

No one will ever -- since there is three producers are 85% of production in California.

That isn't going to change.

There is never going to be a comp.

For people to believe and for the management of that business to deliver, it is probable they should be separate.

Thanks.

And on the execution?

Is that clear enough?

Yes, that's clear enough.

Vicki will answer the rest.

With respect to our efficiencies, I feel like, in California, certainly, we have a lot of potential as we outlined in detail on the earnings call a couple of times ago.

We have the resources available.

We have now put together a team out there that is structured in a way that gives them the best opportunity for success.

We have great people.

We have very experienced people who know a lot about operating in California, who know a lot about the types of projects we are developing.

That is our core business.

We know waterfloods, we know steam floods.

That's the bulk of what we are doing.

Our team understands, quite clearly, how to do that and they are among the best in the industry.

We are accomplishing what we said we would do.

And what we are doing going forward with this increase in capital is we are being very disciplined about how we evaluate and design our projects and implement our projects.

I am quite certain we are not going to lose our efficiency around execution.

And with the resources we have, I feel confident that we are going to continue to see the same results that we achieved in 2013 going forward.

Thanks.

Steve, my follow-up -- given that you have been fairly clear about how this could play out.

California has not been spending its cash flow up until now, so as a stand-alone Company, would there be an intangible drilling cost uplift to the operating cash flow in your estimates?

And if I could lay down a third very quickly, what is the thoughts on the scale of potential Dutch tender buyback if that's still in your thinking.

I will leave it there.

Thanks.

Obviously, California would spend more money and drill more wells.

I'm sure they could generate a lot of tax shelter if that is the question.

Yes.

Basically.

A separate business who competes -- a separate oil company that competes with other medium-sized, or whatever you want to call them, producers, obviously is business that would generate -- basically use its cash flow.

California has the flexibility, however, which -- it could cut back its capital and use money to repurchase shares or something like that if the right sort of environment came out.

Unlike some other things, it is a pretty complete business.

It has a fair amount of gas opportunities when that is available.

It has relatively safe long-term oil.

It has some exciting oil things to do too.

I think it is a fairly complete business.

It is a business where if things get bad for regulatory reasons or price or whatever, it can cut it's capital back, still do well.

It doesn't get caught on the treadmill of higher decline.

You could even buyback shares.

I don't think it will ever be a big dividend producer, but I think on share repurchase, it could do that if conditions warrant.

But if conditions don't warrant, I'm sure they will spend all of our money.

The process of repurchasing the shares from whatever we do depends on the situation at the time.

When we have the money, we will figure out -- when we have the money in hand, we will figure out exactly what the process will be.

But I point out we repurchased around 10 million shares in the fourth quarter.

We wouldn't have done that with the shareholders money if we thought all of this wasn't going to happen.

I think the process of doing it remains to be seen because you might have one stock price you might do one thing, and another you might do something else.

There is no other place to put it.

It's either some kind of share repurchase or -- there isn't really any debt that we can do much with, so I think we have taken down the debt.

I think the next maturity's in 2016, and I am not up for some kind of windfall for bond holders.

All right.

I'll let someone else jump on.

Thanks, Steve.

Ed Westlake, Credit Suisse.

Yes, I've got a bigger picture question just on Permian and then some follows on California.

Those good questions from Doug.

Just on your Permian, how do you think you're going to get a fair price for the light oil that you're producing.

What is Oxy going to do about it over and above what you've already announced with the BridgeTex pipeline expansion?

Thanks.

We're going to let Willie answer that since he's the expert in oil.

Yes, Ed.

Obviously, we've seen a lot of disruptions in pricing between the regions and we are seeing a lot of infrastructure getting built-in.

When we look at our production of roughly 50 million barrels a year, or 150,000 barrels a day out of the Permian, between the BridgeTex pipeline which goes from, essentially, Midland or Permian directly to the Gulf Coast, as well as taking capacity on other pipelines down to Corpus, we essentially go from a two market business, Midland and Cushing, to ultimately getting to Houston ship channel as well is Corpus.

We also get ability to go to US east coast and lots of different places, so I think infrastructure will help us tremendously in that area.

As a follow-on, people are concerned when the crude gets down to the Gulf it's still going to be impaired.

Any thoughts around that?

The work you've done on that?

Well, the thing everyone looks at is the Brent TI.

And as I think about it, Brent is really tied to world prices.

I think what you are going to see is all the grades, as well as TI, kind of come to transportation parity.

Okay.

So no major discounts in your thoughts for the crudes once it gets down to the Gulf other than quality and logistics?

No.

I think prices fixed the price issues.

I will also point out that $97 oil is probably okay for us.

This isn't some bargain-basement price.

We feel pretty comfortable we can be reasonably profitable at $97 and much lower.

Sometimes you lose sight of the absolute price in all of this talk about differentials.

Yes.

That's a good point.

Just on California then.

You gave us initial resource estimates for the Permian.

Would you be willing to give us resource estimates for California?

I know people are obviously trying to have confidence and a resource number from yourselves would obviously help that confidence?

I think what I prefer to do is leave that for another day and another kind of announcement.

Okay.

Well, thanks very much.

Arjun Murti, Goldman Sachs.

Thank you.

Just another follow-up on California where you have a nice growth trajectory here.

It sounds like the greater confidence in it is a bit of the mix here where some of the stuff that has declined is now smaller, and you're shifting more to water and steam floods, which you've historically been very good at, and maybe less reliant on the unconventionals, at least in the scope of the years presented here.

Is that accurate?

And, I guess if so, where are you on the unconventionals from a confidence standpoint?

Thank you.

I will let Vicki answer about unconventional, but just so you understand, I think you've got it but we have a high decline and really no decline -- high decline at Elk Hills and really no decline at THUMS, which was the bulk of the production of the Company.

It originally was nearly 100%.

What has happened is the little wedge has grown and we have made a lot of progress in improving the decline rate in Elk Hills.

We are not fighting as big a decline curve.

What we are doing is we are filling it in with things that are real certain, so that the business has sufficient cash without being on a treadmill to go forward.

I will let Vicki talk about the unconventional here since she is more knowledgeable than I am, for sure.

This year we are drilling 170 unconventional shale wells versus 111 that we drilled last year.

So we increased the number we are drilling this year.

Actually, we had hoped to drill even more than we currently have on the schedule, but we felt like from regulatory standpoint, it was best to take a more conservative approach this year in view of SB4.

We do have some exciting unconventional projects that are in the permitting process, and we expect to bring those online in 2015.

Basically, part of it's the permitting.

Just trying to get the permits in line and ready to go.

The other part of it is that we are continuing with the strategy that we developed, and that is to, as we said, lower our decline and build up a larger solid base of those types of projects.

That really helps prop us up for the unconventional developments.

Is it a question, Vicki, of the scope of what you have there, you want to sure you have enough running room between confidence in the resource and the ability to get permits?

Or are their still questions on all those points?

Yes.

There are questions on all of them.

We do have, as I said, unconventional plays that we feel very comfortable with the development of because they are things we understand, that we already started the process of development.

There is a portfolio that we feel like we can move forward at a fairly fast pace if we have the permitting in place.

There is still some shales that we haven't really tested and evaluated yet.

We're taking the same approach in California as we are in the Permian where we're doing a more measured approach to go out, drill a few wells, do some evaluation, then start some pilot projects.

From their progress to fulfill development.

We're trying to be very prudent in the way that we approach our shale plays that are outside where we're currently drilling.

Great.

Steve, maybe just follow-up on the MENA comments, I certainly appreciate the scale and complexity here and that's going to take some time.

Can you comment that you've identified, maybe, a partner group, which is a key group you're negotiating with and these things can still take time, or is it earlier stage than that where there's still multiple parties that are involved here?

No.

There is a partner group.

That's great.

And a final one on the stock buyback, should we think about this primarily as asset sale proceeds are used for stock buyback, or your balance sheet is strong that it can be an ongoing program even without proceeds?

The business, fundamentally -- the overall business, whatever remains in the Company is able to generate free cash.

We should see -- I think I said at your conference, part of the program would be -- it will continue to grow the dividends at a healthy base.

We will have a little more share repurchase than we have done historically.

You will see share reductions from whatever happens in the asset sales or whatever dividends we might take from anything we separated from the Company.

I think will see the share count come down.

And therefore, the dividend requirement -- the dollar amount of dividend requirement come down.

I think you will see a mix, but I'm very focused on the value of the stock we are buying.

It isn't just about buying shares for fun.

Certainly easier than drilling wells, but I think -- and so you see us come and go as the stock price changes.

Of course there are periods where we can't buy where we have material information, so there may be periods when we can't buy, but generally you should expect to see a regular program at some level, but also some fairly sizable reductions over the next year, I would expect.

Great.

Thank you so much.

Faisel Khan, Citigroup.

Steve, I was wondering if you could clarify some of the comments you had around return on capital employed.

Are you saying -- and you guys have made tremendous effort in getting return on capital employed up over the last 24 months?

I want to make sure I understand.

Are you saying with CapEx going up next year and with the doubling of the rig count in the Permian over the next few years, and adding seven rigs in California, overall your saying ROCE should trend up over the next one to two years?

Product prices aside, yes.

Okay.

Fair enough.

In terms of your comments on California, given that most of you're growth in California is longer life production, and some of your growth in the Permian has a higher decline rate, doesn't it make more sense to keep those assets together as a portfolio?

I'm just trying to understand how you balance the cash flow and decline rate between the two portfolios over time?

Remember, the Permian is effectively two businesses.

There is the EOR business, which generates large amounts of free cash flow.

The question really is -- and it has potential to add this high-growth stuff but still generate large amounts of free cash flow as a business.

We can manage that reasonably well.

California, the potential is currently managed to generate free cash flow.

It will generate a base ultimately of these long life projects, which basically, by the way, answers to some extent your question about the returns.

Because if you turn on a long-life project, your DD&A rate will be low so your earnings will be better because you've got a lot of reserves over a long period.

Every business, standalone business, has to have a base of money to pay for itself.

I understand there's a whole bunch of companies out there that don't, but that is not the way to build a long-term oil business.

California can spend more, fairly, I think, easily, and continue to grow.

In the Permian, there's a lot of competition for rigs, and people and such, and so I think it is a little more challenging in the Permian.

I think California -- I have a map in my office from 1679 which shows California as an island.

There is some truth to that.

Okay.

Fair enough.

Do you guys have an estimate for the return on capital employed for California at the end of the year?

I don't think so.

I think we'll leave those kinds of questions for some other announcement.

Fair enough.

Thanks.

Roger Read, Wells Fargo.

Thanks.

Good morning.

Maybe taking a little stronger or deeper view of the Permian, you mentioned in the preview part the cost and learning curve issues.

Have you done anything in particular to hire people out there, or has it been learning by watching, learning by sharing info and data with some of your partners out there?

I think, Vicki, so as not to frustrate her, went through a long -- we've got a lot of gross wells, the bulk of our production and outcome comes from our own net wells.

So we see enormous exposure to what other people are doing.

We don't actually have to experiment or hire other people.

We can actually see what they're doing.

We hire people all the time, but we're not hiring people from radically different cultures.

We need people who are trained in a return driven, free cash flow kind of culture.

To hire somebody from some small-company, they really have a different kind of culture.

They're more an IRR getting their money back quick and drilling more wells culture.

We don't want to destroy the notion that this is a business about generating money and generating returns.

We are not going to spoil, at least while I'm here, were not going to spoil the stew with a bunch of promoters.

Okay.

As a follow-up, even to those comments, if I remember correctly, we are in a new CEO search mode here.

Is there any update you can provide on that front?

I think the Board will have something to say about that next month.

I expect I will be doing significantly more earnings calls than I had planned.

Okay.

That's helpful.

Thank you.

In the interest of time, this concludes our question-and-answer session.

I'd like to turn the conference back over to Mr. Stavros for any closing remarks.

Thanks everyone for joining us today, and please call us with any follow-up questions in New York.

Thanks again.

The conference is now concluded, thank you for attending today's presentation you may now disconnect.