西方石油 (OXY) 2014 Q3 法說會逐字稿

Good morning.

Welcome to the Occidental Petroleum Corporation third-quarter earnings conference call.

(Operator Instructions)

Please note this event is being recorded.

I would now like to turn the conference over to Chris Degner, Senior Director of Investor Relations.

Please go ahead.

Thank you, Denise.

Good morning, everyone, and thank you for participating in Occidental Petroleum's third-quarter 2014 conference call.

On the call with us this morning are Steve Chazen, Oxy's President and Chief Executive Officer, Chris Stavros, Chief Financial Officer, Vicki Hollub, President Oil and Gas in the Americas, Willie Chiang, Executive Vice President of Operations, and Sandy Lowe, President of our International Oil and Gas Operations.

In just a moment, I will turn the call over to our CFO, Chris Stavros, who will review our financial and operating results for the third quarter and also provides some guidance for the current quarter.

Our CEO, Steve Chazen will then provide an update on the progress of our strategic initiatives and Outlook for 2015.

Vicki Hollub will then provide an update of our activities in the Permian basin.

Willie Chiang will conclude the call with an update on OXY's midstream operations.

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 materially from those expressed or implied in these statements.

Additional information on factors that could cause results to differ is available on the Company's most recent Form 10-K.

Our third-quarter 2014 earnings press release, the investor relations supplemental schedules, and the conference call presentation slides can be downloaded off of our website at www.oxy.com.

I'll now turn the call over to Chris Stavros.

Chris, please go ahead.

Thanks, Chris, and good morning, everyone.

We generated core income of $1.2 billion for the third quarter of 2014, resulting in diluted earnings per share of $1.58, a decrease from both the year-ago quarter and the second quarter of 2014.

The decline in core earnings was attributable mainly to lower oil realized prices on our worldwide production and the sharp decline in trading performance on a sequential quarterly basis.

For the fifth consecutive quarter, we continued our strong domestic oil production growth.

We met our guidance and achieved a year-over-year domestic oil production increase of 20,000 BOE per day, or about 8%, led by our Permian and California assets.

We also repurchased 4.7 million shares of our stock during the third quarter and ended the period with $2.9 billion of cash on our balance sheet.

Oil and gas core after-tax earnings for the third quarter of 2014 were $1.1 billion, $90 million lower than the second quarter of this year and $236 million lower than last year's third quarter.

For the third quarter of 2014, total Company oil and gas production volumes averaged 755,000 BOE per day, an increase of 19,000 BOE in daily production from the second quarter and 6,000 BOE per day for the same period a year ago, which excludes production from that Hugoton assets for all periods.

Our third-quarter 2014 realized oil prices of $94.68 per barrel fell by $5.70 compared to the second-quarter realizations of $100.38 a barrel.

In the third quarter of 2014, after-tax core income for our domestic oil and gas operations was $538 million.

On a sequential quarter-over-quarter basis, results at our domestic operations were negatively impacted by lower realized prices across all products.

Improved volumes, however, offset roughly a quarter of the earnings decline caused by lower prices.

On a year-over-year basis, domestic operations declined by $252 million after-tax, which reflected the impact of lower realized oil prices partially offset by increased oil production volumes.

The lower realized oil prices were impacted by the large differentials we saw in the Permian basin.

Willie Chiang will provide a more in-depth discussion around Permian differentials later on in the call.

Total domestic oil and gas production averaged 475,000 BOE per day during the third quarter of 2014, up 11,000 BOE per day sequentially.

Domestic oil production was 282,000 barrels per day during the third quarter, a new quarterly record for OXY.

Domestic oil production volumes increased by 20,000 barrels per day from the year-ago quarter with our Permian Resources business growing its oil production by 26% to 43,000 barrels per day.

On a sequential quarter-over-quarter basis, total domestic oil production growth was 6,000 barrels per day.

International after-tax core income was $624 million for the third quarter of 2014 with results improving by 8% sequentially due to a lifting in Iraq, which had none in the second quarter, and higher sales volumes in both Colombia and Qatar.

Income for our international oil and gas remained about flat versus the year-ago period.

International oil and gas sales volumes rose by 4,000 BOE per day on a sequential quarter-over-quarter basis.

The improvement was largely due to higher volumes in Columbia which experienced fewer pipeline incidents in the period.

Oil and gas cash operating costs were $14.89 per barrel in the third quarter of 2014 compared to $14.68 per barrel in the second quarter.

Taxes other than on income, which are directly related to product prices, were $2.64 per barrel for the third quarter of 2014 and $2.80 for the first nine months of the year.

Third-quarter exploration expense was $53 million.

Chemical third-quarter 2014 pre-tax earnings were $140 million compared with second-quarter results of $133 million and $181 million in the year-ago quarter.

Although slightly below our guidance, the sequential improvement in the third quarter was due to higher caustic soda prices and volumes, along with lower natural gas costs, offset by a lower vinyls margins resulting from rapidly escalating ethylene costs.

We expect our fourth-quarter pre-tax chemical earnings to be about $115 million, reflecting a historical slowdown -- seasonal slowdown due to the combination of maintenance outages, holiday shutdowns, and some customer initiatives to reduce year-end inventories.

Midstream pre-tax segment earnings were $125 million for the third quarter of 2014 compared to $219 million in the second quarter and $212 million in the same period a year ago.

The 2014 sequential quarterly decline in earnings resulted mainly from much weaker trading performance driven by sharp commodity price movements during the period, partially offset by higher income from power generation and the domestic pipeline businesses.

In the first nine months of 2014, we generated $8.6 billion of cash flow from operations before changes in working capital.

Working capital changes decreased our cash flow from operations by $416 million to $8.2 billion.

2014 year-to-date cash flow from operations declined by approximately $1.6 billion compared to the same year-ago period.

The first nine months of 2014 included tax payments of $570 million related to the gain of the sale of the PAGP units and our Hugoton assets and the first nine months of 2013 included the collection of a tax receivable.

Capital expenditures for the first nine months of 2014 were $7.3 billion net of partner contributions.

Our capital outlays included $410 million associated with the Al Hosn gas project and $275 million for the BridgeTex pipeline.

During the first nine months of this year, we received proceeds of $1.3 billion from the sale at our Hugoton assets and spent about $425 million toward domestic bolt-on acquisitions.

We issued $1.6 billion of commercial paper during the latter part of the third quarter as part of our short-term cash management process which has already been repaid.

After paying dividends of $1.6 billion, buying back $2.1 billion of Company stock, and other net flows, our cash balance was $2.9 billion at September 30.

Our debt-to-capitalization ratio was 16% at quarter-end.

Our 2014 annualized return on equity was 12% and return on capital employed was around 10.5%.

Earlier this month, we received cash proceeds of approximately $5 billion from the bond offering completed by California resources.

IRS rules mandate that the use of these proceeds be restricted to share repurchases, dividend payments, or debt retirement.

We will be receiving an additional $1.2 billion of cash from California resources concurrent with the spinoff in late November.

The use of these proceeds will be unrestricted.

The worldwide effect of tax rate on our core income was 40% for the third quarter of 2014, and we expect to combine worldwide tax rate in the fourth quarter to remain about the same.

Lastly, I will outline some guidance and a few points on our reporting disclosures for the fourth quarter.

Due to the recent sharp decline in oil prices and the completion of the California spin-off at the end of next month, it will be difficult for the financial community to predict our earnings per share for the fourth quarter.

When OXY completes the spinoff of California resources at the end of November, we will reclassify the financial and operational results to discontinued operations for our core results disclosure.

As such, our fourth-quarter core income will exclude all of California results, and income on a reported basis will include two months of California results.

Total year results on a reported basis will include 11-months contribution from our California operations classified as discontinued.

Included in the IR supplemental schedules is a pro forma table segregating OXY's sold and spun-off domestic production from our ongoing operations for the historical quarterly 2013 and 2014 periods.

For the fourth quarter, we expect to see continued production growth from the Permian Resources.

In addition, with the start-up of the BridgeTex pipeline, OXY will capture a portion of the spread between LLS and WTI Midland on approximately 200,000 barrels per day of oil transported to the Gulf coast.

Willie will discuss the benefits of the BridgeTex start-up in a few moments.

We expect our international volumes to increase in the fourth quarter with the Al Hosn gas project coming online and the positive impact of volumes for our production sharing contracts that are sensitive to the decline in oil prices.

On a go-forward basis, excluding California, price changes at current global prices affect our quarterly earnings before income taxes by $29 million for a $1 dollar per barrel change in oil prices and $6 million for a $1 per barrel change in NGL prices.

A swing of $0.50 per MMBtu in domestic natural gas prices affects quarterly pre-tax earnings by about $15 million.

These price change sensitivities include the impact of production sharing contract volume changes on income.

Our fourth-quarter 2014 exploration expense is anticipated to be about $60 million pre-tax.

I'll now turn the call over to Steve Chazen, who will provide an update on some of our strategic and growth initiatives.

Thank you, Chris.

The overall business is operating well, and our increased investment and focus in the Permian resources operation is evidenced by the 24% year-over-year growth in total production.

Other long-term investments such as the BridgeTex pipeline and the Al Hosn gas project should also begin contributing to our results in the current quarter.

We continue to make steady progress towards furthering our strategic initiatives outlined a year ago.

The spinoff of California resources is on track, and we expect to distribute approximately 310 million shares of the new California Company to OXY shareholders at the end of November.

California resources completed its debt financing earlier this month and distributed approximately $5 billion in cash to us as a tax-free dividend on October 9. The dividend of $1.2 billion of proceeds from the term loan credit facility will happen concurrent with the spinoff.

After the spinoff and for a period lasting up to 18 months, OXY will retain approximately 75 million shares of the California Company.

At some point during this period, we intend to conduct an exchange offer for the remaining California shares for OXY shares, further reducing our own shares outstanding.

Over the years, OXY has made significant investments in California oil and gas and has built a solid business.

With the separation of these assets, the California operations will be classified as discontinued.

The resulting impact expect to provide lower unit rates for cash operating costs, DD&A, and F&D costs for OXY, as well as improved reserve replacement ratios on both a historical and an ongoing basis.

Regarding our interest in the Williston Piceance basins, given the current product price environment, we plan to operate these assets with less capital in order to generate free cash and shift our investment towards our higher growth and higher return operations in the Permian basin.

In the Middle East, we continue to make progress negotiation with our partners towards a partial monetization with the goal to improve the business' ability to grow profitably from a somewhat smaller base.

Over time, we expect to achieve a similar balance in our asset mix with roughly 60% of oil and gas production coming from the United States.

Over time, we also expect to monetize our remaining interest in the GP of Plains All American Pipeline, which is currently valued at more than $4 billion, in addition to some other midstream assets when market conditions warrant.

We expect to generate a large amount of cash proceeds from initiatives I've mentioned.

While we expect the bulk of these proceeds will be used to repurchase our own shares, we also hope to invest in the business through attractive bolt-on acquisitions in our core area of the Permian basin.

Opportunities may exist for accretive property acquisitions that have current production and growth prospects and also complement our existing acreage.

We have no intention of acquiring public companies since their current pricing reflects high oil prices and a near-perfect outcome for production.

Since the end of the third quarter of 2013, we have repurchased approximately 31 million shares of the Company's stock for nearly $3 billion.

The Board recently authorized the repurchase of additional 60 million shares of the Company's stock leaving the program with 76 million shares.

We are currently undergoing our annual capital budgeting process and are mindful of the recent decline in oil prices.

A significant amount of long-term investment, including the capital for BridgeTex pipeline and the Al Hosn project, is nearing completion.

We expect our overall capital program to decline in 2015 given the absence of California and the completion of multiple long-term projects.

We also expect significant decline in our spending in the Middle East as we begin to reap the benefits of some of our earlier long-term investments.

The vast majority of capital budget next year will be allocated to our domestic oil and gas drilling operations where we will maintain flexibility in our budget.

We also expect that since the service companies were happy to raise prices when oil was going up that they would be just as happy to have their prices lower in the future.

Some of the reduction in the program and a long-term project will be allocated to profitable growth opportunities in the Permian resources, midstream, and chemicals.

If lower crude oil prices persist or fall further, we will adjust our capital program to manage within our cash flow, probably by reducing, or not growing as quickly, in the back half of the year.

We plan to provide a more detailed capital program for 2015 during the fourth-quarter earnings call early next year.

Excluding California, we expect to see an acceleration of total oil and gas production growth in 2015, given the ample opportunity to re-capital deployment in the Permian resources and the ramp-up of production from Al Hosn.

In the United States, we expect Permian resource to deliver production growth of at least 20% in 2015, primarily from oil.

We expect the resources business to exit 2014 at over 80,000 BOE a day and to exit next year at over 100,000 BOE a day.

Our total domestic production, excluding California, should grow 5% to 8% reflecting a modest decline in our natural gas and NGL volumes.

In the Middle East, first production from the Al Hosn gas project is anticipated later this quarter.

OXY's net share of production is expected to ramp towards 60,000 BOE a day during the first half of next year, Company-wide and excluding California.

We expect our total oil and gas production to grow 8% to 10% next year.

While the recent sharp decline in oil prices may provide some headwinds to the business in 2015, our commitment to a conservative balance sheet with low-cost oil production gives us confidence in our operations and the capacity to make targeted property acquisitions.

We expect our cash balance to exceed our total debt by the end of this year.

OXY is built to thrive in an environment where our core properties in the Permian EOR business and production sharing contracts in the Middle East, which provide relatively stable cash flow.

Following the execution of the California spinoff, California -- OXY's philosophy with disciplined capital allocation will continue.

Our core business will continue to focus on delivering moderate volume growth, generating higher earnings and cash flow per share, as well as improved financial returns.

Our Permian Resources business will represent the key area of growth within our domestic operations.

I'll now turn the call over to Vicki Hollub for an update on our activities in Permian Resources.

Thank you, Steve.

In last quarter's call, I discussed our progress toward reaching 120,000 barrels of oil equivalent per day of production in 2016 by achieving the following goals.

First, correlating rock and fluid properties to production performance across OXY's entire Permian acreage position.

Second, optimizing development strategy and design to unlock full primary development potential, and third, efficiently accelerating full field development and production growth.

We made significant progress on these goals in the third quarter and continue to improve and optimize our stimulation designs for each field and bench.

In addition to testing slick water and hybrid fluid systems, we are testing and analyzing other key variables such as pumping rate, pad volumes, proppant type, proppant concentrations, surfactants, cluster count and spacing, clusters per stage, and alternate technologies to plug and perforate.

Our efforts are driving significant improvements in well productivity in our Delaware and Midland Basin assets.

In the third quarter, Permian resources had daily production of 77,000 BOE per day, which is a 7% increase from the 72,000 BOE per day that were produced in the second quarter.

We produced 43,000 barrels of oil per day for the third quarter.

This is a 26% increase from a year ago and an 8% increase from last quarter.

During the third quarter, our capital expenditures were $472 million.

We operated 24 rigs and drilled 75 wells, including 44 horizontals.

We placed 71 wells on production, including 36 horizontals.

The number of wells drilled and placed on production was adversely impacted by delays attributable to flooding which occurred in September.

This impact reduced the number of horizontal wells placed on production by approximately 10.

We've increased the number of frac spreads in the fourth quarter to address the additional [carry-in] well inventory.

In the fourth quarter, we plan to operate an average of 30 rigs and exit the year with 34 rigs.

We expect to drill 80 wells and placed 75 wells on production, including 48 horizontals.

Before discussing the third quarter activity in greater detail, I would like to share some more information regarding the drilling potential we see on our acreage.

OXY's unconventional plays in the Permian are spread across 2 million acres in the Midland Basin, Central Basin platform, Northwest shelf, and Delaware Basin.

Our teams continue to utilize our extensive knowledge and appraisal work to characterize prospective benches and target landing zones within each bench.

To date, we've identified approximately 7,100 potential well locations.

Overall, more than 92% of the locations are horizontal, and our results confirm the economics of horizontal wells exceed most vertical wells.

In the Delaware Basin, we have currently identified 4,250 horizontal locations with 1,450 in the Wolf Camp A and B benches.

The majority of these locations are in our operated areas in Reeves County.

The Bone Spring potential is equally as significant with 1,500 potential locations.

These are primarily located in New Mexico and could increase with further success in Texas.

In the Midland Basin, we've identified 2300 horizontal locations, and 1,050 of these are in the development phase targeting the Spraberry, Wolfcamp A and B benches.

We are highly encouraged with recent result of these benches achieved through our frac design optimization and increases in lateral length.

In the Delaware Basin, we operated 11 horizontal drilling rigs and 1 vertical drilling rig in the third quarter.

We drilled 41 wells and placed 40 on production.

In our Barilla Draw acreage, we placed eight horizontal wells on production in the Wolfcamp A and B benches.

These wells achieved a peak rate of 1,355 BOE per day and a 30-day rate of 1,067 BOE per day.

Our Ryman 14 5H well achieved an average peak rate of 1,600 BOE per day and a 30-day rate of 1,365 BOE.

We completed our first Delaware zipper frac on the Anna Catherine 5H and 6H, reducing completion costs by $700,000 due to the efficiency gained from simultaneous operations.

These two wells achieved an average peak rate of 1,600 BOE per day and an average 30-day rate of 1,225

The production rates achieved on our wells placed on production in the third quarter are significantly above our first-half 2014 rates.

This increase is directly attributable to the breakthroughs we are achieving in our optimization program including increasing sand concentration, lengthening laterals, and optimizing cluster spacing.

Additionally, our Wolfcamp A wells are matching the 900,000 BOE type curve, and production from our horizontal wells in the Delaware Basin is averaging 89% total liquids, 77% oil.

Our appraisal efforts in the second Bone Spring and Wolfcamp C benches in the Delaware Basin continued in the third quarter.

We were excited to see enhanced performance from the Bone Spring and anticipate further gains as we incorporate learnings from the full core we acquired in the third quarter.

These learnings will drive improvements in 2015.

Additionally, we are encouraged by recent results achieved in the Wolfcamp C. Our Topsy 206H well achieved an average initial rate of 1,356 BOE per day and a 30-day rate of 912.

In the Midland Basin, we operated eight horizontal drilling rigs and four vertical drilling rigs during the quarter.

We drilled 34 wells and placed 31 on production.

We are very encouraged with the results of the Sprayberry bench and plan to accelerate development of this bench in 2015.

During the third quarter, we placed the South Curtis Ranch 3526H well on production.

This well was completed in the Lower Spraberry bench and achieved an average peak rate of 934 BOE per day and an average 30-day rate of 913.

We have two additional Spraberry wells on flowback with initial production results that look similar to the South Curtis Ranch 3526.

These wells are exceeding the 700,000 BOE type curve.

In the Spraberry Wolfcamp A and Wolfcamp B, we placed a 11 horizontal wells on production in the third quarter with a peak rate of 731 BOE per day and an average 30-day rate of 541.

Production from these wells averaged 91% total liquids, 81% oil.

We continue to gather and evaluate cores, cuttings, advanced logs, microseismic tracers and pressure data to link reservoir characterization to well performance.

We have recently acquired 474 feet of continuous horizontal core from one of our Wolfcamp B wells.

This will allow for better definition of lateral reservoir lithologic variations and enable us to tune those differences to open-hole logs to optimize placement of perforation clusters and improve frac design.

We're making significant progress in our design optimization efforts and are confident this will translate into further improvements in well productivity in upcoming quarters.

For example at Dora Roberts, we drilled a 10,000 foot lateral in the Wolfcamp B bench.

This well, the Dora Roberts 4027H, achieved a peak rate of 1,437 BOE per day and a 30-day rate of 671.

This well is exceeding the 650,000 BOE type curve.

Additionally, we recently drilled the Hendricks 1H well at Guitar that achieved an average 30-day rate of 775 BOE per day.

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

We continue to make rapid progress translating the knowledge gained in our appraisal efforts to create value from our unconventional acreage.

We have positioned the required resources to execute accelerated development in 2015, but maintain the flexibility to optimize our portfolio and pace.

We're on target to deliver 15% to 18% production growth in 2014 and remain confident that we will achieve our target of 120,000 BOE per day in 2016.

I'll now turn the call over to Willie who will provide you an update on the Permian marketing strategy.

Thanks, Vicki.

Good morning everyone.

I'd like to just take a few minutes to briefly update you on our midstream marketing strategies in the Permian.

It's particularly important in today's market environment to maximize realized value for our production, and our strategy to do so is primarily by ensuring access to markets.

Now, I spent some time last earnings call on our midstream strategy to show you how we're trying to develop and secure takeaway capacity in the Permian basin.

I have a slide 29 that shows our strategy, which is really focused on two new takeaway points: Colorado City, which is the origin of the BridgeTex pipeline, and Midland South which is the origin to key third-party pipelines, Long Horn and Cactus.

These takeaway points complement our Centurion gathering system by providing us the additional access to multiple markets.

Now, as you are aware, the BridgeTex pipeline commenced service this September and together with the start-up of some additional pipelines in the next few months, we expect differentials to return to levels that will reflect the marginal cost of transportation.

Slide 30 shows the pricing differentials for Midland WTI versus LLS.

During takeaway-constrained periods, you can see the LLS Midland differential widened to $30 a barrel and has averaged approximately $16 a barrel over the past four years.

In 2014, the LLS Midland differential has averaged $12 year-to-date, and today it's currently roughly $10 a barrel.

Our unique upstream and midstream perspective to the Permian basin has enabled us to be a driving force behind the construction of new pipeline infrastructure, as well as takeaway capacity from the basin.

Slide 31 shows how we view the key value components for infrastructure projects such as BridgeTex.

As a standalone pipeline investment, we look at tariff revenue to ensure a solid return consistent with our targeted rate of return for domestic midstream projects.

This can generate cash of roughly $1 to $3 per barrel.

Second value driver is when we enter into long-term and cost advantage transportation commitments on pipelines as a shipper.

This gives us sufficient access to markets compared to other transportation routes and options.

Depending on the project, advantage tariffs can add another $1 to $3 a barrel of incremental value.

However, the point I want to make is that the critical value for OXY is really to avoid discounted prices that result from infrastructure constraints and unplanned outages.

The value is significant, and if you look at the past four years, can be $10 a barrel or more.

Now, our significant takeaway commitment on BridgeTex is a great example of how we capture this value, and in today's market, is roughly $1 million a day for OXY.

Our Permian Basin strategy utilizes all these value drivers to reach multiple markets, and we have secured access to long-term takeaway capacity of roughly three times our current production from the basin.

Now, this really positions us well to continue to grow our production, maximize realized prices, and capture market opportunities.

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

Thank you.

Thanks Willie.

Denise, we are ready to take questions.

(Operator Instructions)

Evan Calio, Morgan Stanley.

Good morning.

Steve, my first question is most of your large-cap E&P peers are increasingly can live within cash flow or more limited by their balance sheets.

Given OXY's underleverred balanced sheet versus anybody other than a super-major, would you be willing to outspend cash flow in a downturn as a method to right-size your balance sheet?

Or, really I guess what is the right or targeted capital structure for OXY moving forward?

Well, first I would argue, we're better capitalized than the majors.

So, I think they are over-leveraged myself.

But anyway, I think as Chris pointed out, we're going to have a lot of cash at the end of the year from a variety of sources, mostly from the California business.

Some of that, of course, will be used to reduce our share count -- maybe the bulk of that to reduce our share count.

We continue to look for opportunities to grow the business in the Permian through investment.

So, to sum -- well, our drilling program may be in line with cash flow, if we see other opportunities to -- small property acquisitions or even medium-sized ones, we'll use our balance sheet to do those.

And, those would effectively be an increase in the program in excess of cash flow.

So, I think we've always had a balance of drilling and acquisitions.

It's more shifted clearly to drilling now.

Because we have so much to do, but I think -- I don't think you'll see massive changes in our leverage, but you will see obviously less equity in our equity account as we buy down a lot of stock.

So, I think it'll always be a balance.

If there was a sharp reduction in oil prices, created more buying opportunities, we wouldn't hesitate to increase our leverage to grow the business.

So, I think that from our perspective, this is sort of good times.

I know what to do at $75 oil or less, but I have no idea what to do at $120.

So, I think this is really good times for us.

It may not be good times for people who use us as a proxy for oil price -- use our stocks as a proxy for oil price.

But, as a fundamental business matter, these cyclical downturns is where you use the balance sheet to build the business.

And, I think that's -- I'm hoping -- a lot of happy talk now especially from service companies about how this is temporary.

I don't know how anybody knows that, but if I could predict oil prices, I'd be sitting on a beach in Galveston and wouldn't come to work and wouldn't mess with this production business.

So, I think that as a practical matter, you got to -- this is a volatile time.

There may be a recession worldwide.

I don't really know.

I don't see that.

But, a little lower oil prices, I think, could take some of the buoyancy out of it and gives us some opportunities to add to our business.

So, our goal is to grow our earnings per share, our reserves per share, cash flow per share, through a combination of share reduction, and hopefully building the business either through drilling or acquisitions and maybe both.

Well-positioned for a down market.

Maybe a related question.

But on buybacks, you used to have the slide where you built up to a 100 million share buyback, and I guess there's two questions.

It is not included today, if there's any change in thought there, and secondly, when you did the 100 million share potential buyback, it was determined when OXY was $100 a share.

It is $89 today.

All things being equal, it will be lower following the CRC spin.

And, at the same time, the elements that are funding the buyback are largely flat.

So, I guess, is there -- how do you think about that, which is it approximately about $1 billion Delta?

Or, is it -- listen to -- ?

We denominate this stuff in shares.

Because that's the way we think about it.

How many shares are we buying back.

We're fairly -- somewhat disciplined in making sure that we don't buy shares at prices that imply -- that are excess of our finding and development costs.

So, I think that's the way we look at it.

We announced the share repurchases as we actually have the cash in hand.

It's not intended as a forecast of what we might ultimately do.

As more cash comes in hand, you should expect that the share repurchase authority would rise.

So, the 60 million shares we've added -- so we've got 76, I think roughly left to go.

You should view that as the cash in hand number.

Not the ultimate -- the ultimate will be dependent on the pace of proceeds from various things.

So, I think we're not trying to forecast.

We are going to say this is what we've got in our hand now.

If it turns out that we have excess money because the price of stock is too low, we'll adjust the share repurchase to higher numbers.

Got it.

Is there -- how would we consider a timetable?

Is that -- for the buyback?

Given it's significantly higher than level historically?

Or, is it still just going to be a level-driven program?

It's driven principally by the stock price.

So, we look for buying opportunities in the market when people become irrational.

Got it.

Appreciate it.

Thanks.

Thanks.

Doug Terreson, ISI.

Good morning, everybody.

Good morning.

Steve, I have a couple of questions about the main E&P business.

First, from a strategic perspective, there's been commentary about divestitures in Oman and other countries.

So, whether or not you comment on assets individually or the positions in general, I wanted to see if we could get an update on likely strategic outcomes there and/or the environment for monetization.

Meaning in general, what you have talked about in the past.

And, the second question is that you mentioned that Al Hosn was going to start up on time in the current quarter which is good.

So, the second question is whether it's going to come in on budget as well?

So, two questions.

The second -- we will have Sandy answer the budget question, but it's sort of a one-word answer.

But, on the overall reduction, it's one at a time, but our objective is the same, one way or another to get value out of the Middle East business.

Some by selling it and maybe some by speeding up the cash out of the asset where it's more difficult.

So, one way or another, we are basically using the business to downsize the size of that business -- make it less important in the Company.

Still an important part, but it's going to be a lot of cash is going to come out of that business, one way or another, over the next few months.

Okay.

I think we are going along slower than I would like, of course, but to some extent by showing -- being too anxious sometimes you get a worse result than you might get some other way.

So, Sandy will answer the question on budget here.

Okay.

The answer is one-word.

Yes.

We are on budget.

It's a well-planned project and well tendered.

The start-up sequence has been initiated, and we expect to have some product sales in the quarter.

Great.

Thanks a lot.

Thanks.

Doug Leggate, Bank of America.

Thanks.

Good morning, everybody.

Steve, I also have two questions.

I guess my first one is for Vicki.

I really want to talk about the Permian -- or ask about the Permian growth trajectory that you have provided for us.

Your run rate since you ramped up the rig count has been about 5,000 barrels a day per quarter, and I realize it's very simplistic just to look at the absolute move sequentially.

But, you are significantly accelerating the rig count and the back log it looks like.

So, I'm just trying to reconcile a substantially higher activity level with a similar quarterly rate of growth at least implied by your projections for the next couple years.

That's my first question.

I've got a follow-up, please.

I'll let her answer the question, but I think I wouldn't confuse our expectations with our promises.

There's probably a wide difference between them.

Go ahead, Vicki.

Yes, Doug.

Originally, we had not planned to reach the exit rate this year with 34 rigs.

But, we've accelerated our development a little bit, and as you noticed, we are a little bit behind on some of our wells completed.

But, we've added another couple of frac spreads.

So now, as of first of November, we will be at 7 to address the well inventory.

And, with respect to the rigs going forward, we still intend to stay somewhat as per the schedule that we had showed in our last presentation.

We are just seeing a little more opportunity here to get a little bit ahead of the game.

So, this is not a working interest issue or anything like that, Vicki, in terms of subsequent wells from here having a lower working interest?

Maybe you could give us an idea of what that [actual] work interest is?

Well, we gave you an indication on the slide in the presentation that for the Midland Basin, generally speaking, our working interest is close to 92% overall.

And then, the Delaware Basin around 76%, generally speaking.

Okay.

Thanks for that.

Steve, my follow-up is really -- I realize were going to have to wait on the capital to the end of the year, but just as an order of magnitude.

I wonder if you could help given all the moving parts with California going, BridgeTex and Al Hosn largely done.

What I'm really trying to get at is how you think about balancing spending with the dividend as opposed to asset monetization funding the buyback.

How should we think about dividend policy?

And, maybe a broad scale of spending for next year, if you could.

Thank you.

It's hard to do the budget right now, because there's a number of moving parts, and we have to talk with our partners in the Middle East about the size of the program there.

I'd just as soon not telegraph our thoughts right now.

But I think our Permian program certainly for the first half of the year will be what we told people that it would be.

I don't expect any real change in that.

Some of the other stuff may be tweaked a little bit and some of the other programs.

We just don't know, but as far as the dividends are concerned, I think if you go back to the slide we've only shown for -- I want to say 10 years, but I think Chris is shaking his head that it's more.

It says after maintenance capital, which is making the Company safe, the next line is dividends.

Before growth.

So, we view our commitment to the shareholders on dividends to be part of our overall commitment.

How much exactly you're going to raise the dividend by remains to be seen, and there's obviously a little confusion with the lower oil prices.

But, I think -- I don't think -- we've raised the dividends I think for a dozen years.

I don't think were going to break the [scheme] next year, and so I assume the dividends will go up.

We've got a lot of cash and a lot of projects to fund almost anything we want to do.

And so, I don't think anybody should be concerned.

We are focused on making sure that the drilling program delivers the results it's supposed to deliver.

If it delivers the results it's supposed to deliver, there'll be plenty of money over the next two or three years for dividends -- dividend growth -- continued dividend growth and share reduction and lots of growth in the business.

So, if we deliver the results that we are doing so far and our plans are pretty much on target, there will be plenty of cash flow and I don't think anybody should worry about where it'll be a couple of years from now.

Next year is going to be a messy year.

You've got comparisons against a Company with a different set of assets.

They are going to have some sales of things next year.

And, the share count is going to be really confusing.

For example, the pro forma is now, for this year, use the average shares outstanding for the year to do the EPS calculation which is a lot more than the shares outstanding right now.

Nevermind at the end of the year.

So, a lot of confusing numbers over the next year.

I think if you focus -- if I were looking at the Company, I would focus on our program in the Permian Resources and our cash generation in the rest of the business, and we've got a lot of --.

I think we've now fixed the realization issue out of the Permian basin that we faced the last three or four years.

Unfortunately, we may have fixed it for everybody in the basin.

But, we certainly -- but we fixed it for ourselves so I'm pretty optimistic about where we are next year.

Great.

Thanks a lot, Steve.

Thank you.

Leo Mariani, RBC.

Yes.

Hello.

I was wondering if you could address a little bit more the comment that you all had made about potentially moderating activity.

I think the phrase you used is if oil prices stay here, or move lower, and you referred to the second half of 2015.

Is there any more granularity you can give around that?

I recognize the budget is not done yet and there's moving parts.

I know you have ambitious plans to ramp up the rig count in the Permian.

Is there any scenario you can paint -- whether or not you stop ramping rigs in the second half of the year.

Would you actually drop rigs?

Can you maybe just talk through that a little bit?

I don't think we have any plans to drop rigs.

The ramp rate is what we would fool with because the businesses would continue to drill wells, put them on stream, generates cash -- more cash than some people are outlooking, and so I think we'll be okay.

We certainly have the financial flexibility to weather that.

On a long-term basis, we are fairly optimistic about oil prices.

Over the next year or two, I don't know.

But, I think on a long-term basis, the industry -- despite what people say, the industry -- US business is not healthy at $70 oil.

And so, I think higher oil prices are in the cards over time.

Okay.

And, I guess just in the Permian, could you maybe talk to what type of well cost you are seeing on the midland side as well as the Delaware side?

Yes.

Vicki can probably answer that.

Yes.

Depending on the depth in the Midland Basin, we are seeing well costs that are in the $7 million to $7.5 million range for our South Curtis Ranch and some of the areas around that.

In the Delaware Basin in Texas, we're seeing well costs in the neighborhood of $8.6 million to $8.7 million, and our drilling costs have been improving through some of our efficiency initiatives.

But, it's really the completion costs that are driving our total well cost right now.

What we've done recently is increased the size of our frac jobs, which is giving us better productivity and better -- what we think will be better ultimate recoveries.

So, when you're seeing higher well costs for us, it's because we are increasing the size of our fracs.

That's helpful.

Is there any approximate lateral length you can put around those well costs at all?

Around the $8.6 million to $8.7 million, that's generally a lateral length of about 4,500 to 5,000.

And, in South Curtis Ranch area, our lateral length is around 6,100.

Okay.

That's helpful.

In terms of your Bakken and Piceance assets, you had in your slides that you planned to limit capital there.

Could you talk about longer-term plans for those assets?

I know you had spoken in the past about some of the Bakken properties and also putting the Piceance assets into a JV for maybe an eventual IPO.

I guess you also talked about additional midstream sales when market conditions warrant.

Could you maybe just talk through strategically how you're thinking about those assets?

Well, the issue in the Bakken is it simply doesn't -- can't compete for the returns being earned in the Permian.

It's not that they're bad assets or anything.

It's just not competitive in our portfolio.

And, the Piceance is all gas.

Gas is tough to compete in this environment.

So, we'll be looking -- and I don't see any way to change -- I'm not bullish about gas prices.

I don't see any real way to change the relative competitiveness of North Dakota versus the Permian.

We can move oil out of the Permian by pipeline.

That's a much more efficient way to move oil than by train.

So, I just think that it's -- just will not -- for our portfolio won't be able to compete so ultimately we'll have to deal with that.

All right.

That kind of implies an eventual disposition, I would assume, at some point?

Yes.

Sure.

Okay.

Right now, it's a little noisy so it's probably not the perfect time to be doing that.

Okay.

Makes sense.

Thanks.

Thanks.

Ed Westlake, Credit Suisse.

Yes.

Good morning.

An intriguing comment from you there, Steve, just on saying cash flows being underestimated.

Obviously, oil prices make it a lot of volatility, but maybe some color on that?

Is that because you think your promise is going to be exceeded by your expectation on volumes?

Do you think it's because cash margins are being underestimated as you shift drilling in the Permian.

Is it Al Hosn, or is it all three and something else?

Generally, I think people have underestimated the cash flow that will come out of the assets.

They basically take what we did this year and add 2% or something to it and then adjust for price.

The Al Hosn project will certainly add.

There's other things that I think will add, but I think we show you -- I think, in this there's a difference without -- we look different without California.

And, we give you some numbers to help you model that.

We don't know what the DD&A rate will be next year because it depends on reserves.

But, the underlying DD&A rate, for example without California, in the United States is lower.

And same thing with operating costs and other things.

So, I think there's -- people are just taking the old numbers because that's really all they had.

But, I think as you look at it, maybe a little more careful modeling with the new numbers might be more helpful for people.

Okay, great.

And then, a question on the Permian.

Obviously, if you look at the Midland, you've outlined Dora Roberts, South Curtis -- these are sweet spots in the northern Midland.

But, it's not a huge amount of acreage, but it will be very productive.

And then, in the Reeves-Barilla Draw area, you've got this fantastic results again, and that's obviously a larger acreage position.

So, that drives growth over the next five, maybe six, seven -- maybe even longer years.

When I look at the rest of the Permian, and particularly say if oil prices did have a longer excursion to the downside, how do you think the returns stack up?

And, I'm particularly say looking at the New Mexico Delaware.

What is the break even oil price you need for getting an acceptable return to drill there?

I get to take a longer view, I guess, because it's a smaller proportion of my age.

So, if I look back two, three years ago, what we thought about the Permian basin and what we thought internally -- forget what other people were saying.

And, I look at the programs that have been proposed now, it doesn't even look like the same Company.

I think as we progress, we continue to find new things that we didn't think of before that will add considerably.

I think the business -- ultimately, if oil prices stay low -- whatever you want to call the current price or at this level or lower for extended period of time, margins historically have adjusted by the reduction of service costs.

You are not going to get an environment where oil prices stay at say, $75 or whatever you think for four or five years, and service costs are going to be the same.

It just isn't going to work, and so part of the gain sharing and loss sharing here will be from both parties.

So, all the money isn't going to go into service company coffers, and we are going to work for free.

And, I don't -- not just we, but everybody.

So, I think in the end, it will equilibrate, and we'll generate acceptable returns.

We think there's a lot of economic oil at $75.

Economic meaning that we earn 15%, 16%, 17% returns.

Do I think there's a lot of economic oil at $50?

No.

I don't.

And, somewhere in that range, but it also depends on service costs.

But, if oil prices go back to $100 or whatever again, service costs will rebound with that.

So, I just think that this thing will take -- work itself out over a one or two year period.

I hate to say it this way but I look forward to a little stress and some of the crazy stuff sort of goes away for a while, and that gives sort of rational people an opportunity.

And then, a final question just on the 2015 production Outlook.

That's very helpful.

8% to 10%, and you can see obviously the great contribution from Al Hosn which you'll probably still have a bit of tail-end to contribution, maybe even in 2016 as well.

That's right.

And obviously, reducing activity in the Mid-Continent.

Do you think the Permian -- it seems from the well results and the activity level, do you think the Permian can provide an offset to keep that production growth at a similar pace in 2016?

Or, does it just naturally slow as Al Hosn comes down?

Al Hosn won't -- it will eventually flatten.

That's what I'm saying, [the growth] rate on that one.

But, I think at Al Hosn I think it's possible that over -- in the next few years, the plant is larger than it needs to be for the deliverable gas, and the country continues to need gas there.

And, the resultant liquids, of course.

So, I think over time, there will be an expansion probably.

It's [totally] up to the government, and so there'll be -- Al Hosn is not through.

So, I think as we look at 2017 and 2018 and 2019 -- we'll see more growth out of Al Hosn.

At some point, it will level off, that's true.

But, I think it will continue to grow, because once you've spent the base money, the incremental capital will have really good returns, I think.

So, I think that'll do better.

I think the Permian resource business has the potential to cover -- to continue to grow and maybe grow better going forward as we work through some of the historical issues.

I think we've got more acreage and more will prove up.

The Barilla Draw didn't really exist a year ago.

The land did, but the concept didn't exist.

And so, I think there's a lot of good concepts out there.

Some will work, and some won't.

Some are -- I think, over-promoted by some, but it's hard to imagine that on 100,000 acres, you're going to have 4 billion barrels of reserves.

But, I think rational expectations are good for the baseline.

The Permian Basin is the best basin in the United States and will be for the next 20 or 25 years.

Thanks very much.

Thanks.

Jeffrey Campbell, Tuohy Brothers Investment Research.

Good morning.

First question I wanted to ask refers to slide 27, the SCR 3520 6H Sprayberry well.

Is the early shallow decline consistent with your expectations?

And does this early positive result have any influence over your Sprayberry appraisal plans going forward?

Yes.

We're still evaluating that South Curtis Ranch 3526, and the shallow decline on that is so far good news for us, but we still want to see a little more production data from that to determine what's causing that.

Great.

Thank you.

And just as a broader question, just looking at your plan as it's unfolded in the permian over the last several quarters.

It doesn't really appear to encompasses the Central Basin platform where some peers have drilled some noteworthy horizontal wells.

I was wondering if you have any horizontal exploration potential in that area?

We feel like we have a lot of potential on the Central Basin platform, and that's just one of the areas that we have yet to get to.

We're working on a fairly structured plan with respect to our exploration, our appraisal, and our development programs.

And so what we showed you on the slide that has the breakout of the zones that are currently under appraisal and currently under development.

That list does not include what we're doing from an exploration standpoint.

So our exploration group is -- one of their key areas to focus on over the next couple of years will be the Central Basin platform where we do have significant acreage and we think there is a lot of potential there.

So it just hasn't gotten in the queue yet, but it's something that we're optimistic about.

It's a nice problem to have.

Thanks very much.

Roger Read, Wells Fargo.

All right.

Thank you.

Good morning.

Hopefully I'm on.

Anyway, quick question on the OpEx side, a couple years ago started an OpEx reduction effort, obviously it was successful.

This time around talking about OpEx and then last night on the call with CRC, they talked about higher gas prices.

I was wondering ex-California if you could walk us through what the OpEx issues are here, and how much of that is due maybe to just temporary gas price increases, and how much of it is a function of maybe changes in what you're doing in the Permian Resources area?

Just as you look at OpEx, I think there's two -- there is a cost of energy, which is buried in OpEx because we use a lot of electricity to run pumps and such.

So some of that's in energy and some of it is in the -- basically driven by the EOR business, which uses -- where the gas to CO2 is tied to oil price and they use more -- a little more CO2 and we expense that.

It looks as though that was an operating cost, and some of it is we increase the workover activity principally in the EOR business.

So when you look at our numbers for operating cost in the United States, the driver -- the overwhelming driver is EOR business.

Which is basically a low capital business but a little higher operating cost business than say the resources business, which is a high capital business and a low operating cost business.

So what you see is, as we put more CO2 in the ground, as we try to repair the wells, you get more operating cost, and we try to optimize that and what we look at is the base -- the underlying operating cost, not so much what were doing from quarter to quarter.

We can't do anything about CO2 prices or anything like that.

So I think it's a mix of things but the driver for operating cost for the OXY, excluding California, is the EOR business, which is a large business and its principal expenses are not capital but rather operating costs.

So, it just looks a little different than you might be used to.

So with California, it's soon to be gone.

We actually show you somewhere -- Chris?

Yes.

We gave you a pro forma slide table in the IR schedules that shows pro forma without California and the Hugoton for cash operating cost, DD&A, and some other metrics and also production so you can go back and model it off of that and you'll see what happened over that period of time.

Okay.

We'll do that.

And then the other question I had was along the lines of catching up on the well completions and the addition of the frac spreads in West Texas.

Any chance for upside performance in terms of production there relative to the guidance, or is that all fully incorporated in the numbers?

That is incorporated in our projections for production, so we do expect to catch up and we've accounted for that.

I think what he's asking is, have we been conservative in the number or not?

I'd say that based on the performance we've seen thus far, I'd say that's a conservative number actually.

It's an achievable number.

Okay.

That's very helpful.

Thank you.

Paul Sankey, Wolfe Research.

Thank you.

Good morning.

Good morning or whatever it is.

Or afternoon I guess.

A couple of high level strategic questions.

Firstly, do you think you've been behind technically in the Permian?

Do think you can get ahead?

Do you think any kind of technical advantage is sustainable in the US unconventional given the commoditization of the activity?

We'll start with -- yes, we're behind.

I think somewhere earlier I said, if I look at what the presentations internally were two years ago, and I look at the quality and the detail of the current presentations for next year's program, it doesn't even look like the same Company.

So I think we've made a lot of progress.

We are blessed with good acreage, which compensates for whatever to some extent.

So I don't think it's -- I don't think there's much -- I always believe that it's the acreage or the reservoir that overwhelms over time technical -- technology spreads quickly.

So I don't think there's some -- there's no secret sauce that lasts very long.

So I think as a practical matter, I think we're where we need to be in technology.

There's always going to be improvements.

Whether you have relative improvements against other people, I don't know.

But over time the technology spreads very quickly.

And so -- because we see lots of wells so it's not really something that's hidden from us.

So I think where we need to be from a skill set right at this point -- we were behind.

There's no argument about that, but we are fortunate that we have an exceptional acreage position; which in the end, the reservoirs matter.

I guess the argument there would be that you were in early relatively speaking and paid less, but above all the early entry allowed you to get the better acreage?

Is there any other proof by the way that you have better acreage?

How can we show that?

Maybe Vicki can tell you about that.

I'd like to build on Steve's comments with respect to your first question initially.

Technically, we have teams here with OXY that I think could compete or beat any other teams in the Permian basin at this time.

From a success standpoint and the unconditional plays, one of the critical things is to understand what the reservoir is and what the reservoir's telling you.

We don't believe that these plays should be called statistical plays.

We think that you've really got to understand what the reservoir is, and based on what the reservoir is, you design your completions and your frac jobs.

And I think right now we're probably one if not the only company -- one of the few companies that's actually taken a horizontal core; and along with our vertical cores, our 3D seismic, our micro seismic, and all the additional work that we're doing around reservoir characterization, I think nobody in the basin is any further along than we are with respect to that.

But I think with that said, the industry as a whole still has a lot to learn.

We're all very early in the development of these unconventional plays in the Permian.

So I still think that we're going to continue to learn, technology will continue to advance.

And I think that as it does, I expect over time for costs to come down on -- at least from the drilling standpoint and possibly from the completion standpoint.

We've got some plans in place over the next six months to do some things I think that could have a significant impact on our productivity and ultimate recoveries.

But it's just a matter of working those costs to make sure that they're economical for what we want to do.

And as I said, technology over time, the cost comes down.

And so I think will be able to do some things that will certainly help some of the areas that previously have not been as good as our Delaware basin area.

So, I'm sorry -- now I've forgotten your second question.

I was just saying, is there some way that we would be able to show easily that your acreage is superior to someone else's?

Well, we've got so much of it that -- some of it's going to be better and some not.

I mean if you compare it to some guy that's got 100,000 acres and that's his whole position, who knows?

But I think if you look at the overall result and you say we started from a standing start two years ago and we'll pass 80,000 at the end of this quarter.

And we'll pass 100,000 at the end of -- by the end of next year for sure.

So I just look at -- from a standing start two years ago, we'll be one of the biggest producers in this unconventional in no time, but our whole business historically had been an EOR business.

So, it's whatever you want to think, but I think -- there's always somebody who's got 40,000 acres that's real good.

The question is, can you have 2 million acres that's real good?

And I think we've got enough 40,000 acre pieces that we can compete with anybody.

If we took one of our 40,000 acre pieces or 100,000 acre pieces and people were saying what a wonderful Company it is.

It's as good as the snake company or whatever it's called.

Got a couple of quick ones, Steve.

The investment in midstream is simultaneous with the sell down of the GPS Plains All American, I assume that means that you wouldn't be continuing to want to own this asset long-term.

And further to that, does the deliberate naming of Permian Resources rings a bell with California Resources, I wondered if that was a potential spin candidate and I'll leave it there?

Thank you.

On the midstream, our goal is to -- I think as Willie pointed out, our goal is to make sure that we get the best possible price for our product and we are not disadvantaged.

We've gone through several years of disadvantage.

If we can do that without spending capital to build pipelines, we're happy to do that by committing for space and reaping the advantages of owning space, and so I think you should view it as -- its purpose is basically to make sure we get good prices for oil.

If we can monetize -- take back some of that capital someway and put it somewhere else with higher returns, we're definitely going to do that.

As far as the name is concerned, that's sort of an accident.

I wasn't all that wild about the California Resources name, but I think -- I don't think you should view it as a spinoff candidate at this point.

It needs right now the cash flow from the rest of the business to accelerate its drilling, and it's unlike California.

California is actually a good business, but it's in a mature phase where it can be self-financing.

The resource business needs cash to grow, and it's just not the right time to even think about something like that.

Thank you very much.

Thanks.

Ladies and gentlemen, this will conclude our question-and-answer session.

I would like to turn the conference back over to Chris Degner for his closing remarks.

Hi.

Yes.

Thank you, everyone, and please give us a call if you have any follow-up questions.

Have a good day.

Ladies and gentlemen, your conference has now concluded.

We thank you for attending today's presentation.

You may now disconnect your lines.