西方石油 (OXY) 2015 Q1 法說會逐字稿

Good morning and welcome to the Occidental Petroleum Corporation first-quarter 2015 earnings conference call.

(Operator Instructions) Please note this event is being recorded.

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

Thank you, Rocco.

Good morning, everyone, and thank you for participating in Occidental Petroleum's first-quarter 2015 conference call.

On the call with us today are Steve Chazen, OXY's President and Chief Executive Officer; Vicki Hollub, Senior Executive Vice President of Occidental and President, OXY Oil and Gas; Chris Stavros, Chief Financial Officer; 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 CEO, Steve Chazen, who will provide an updated outlook for 2015.

Our CFO, Chris Stavros, will review our financial and operating results for the first quarter and also provide some guidance for 2015.

Followed by Vicki Hollub, who will provide an update of our activities in the Permian Basin.

As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of 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 the results to differ materially is available in the Company's most recent Form 10-K.

Our first-quarter 2015 earnings press release, the investor relations supplemental schedules, our non-GAAP to GAAP reconciliations, and the conference call presentation slides can be downloaded off our website at www.oxy.com.

I will now turn the call over to Steve Chazen.

Steve, please go ahead.

Thank you, Chris.

Yesterday we announced that Vicki Hollub has been named to head our worldwide oil company and will succeed me as CEO when I retire.

Both of us will be visiting shareholders, either at conferences or in their offices, over the next few months.

My commitment is to remain in place until the Board and Vicki feel it is time for me to move on, but not any longer.

Vicki has worked for OXY for over 30 years.

She has had a number of very challenging assignments over the years, including Operations Manager in Ecuador and Russia.

In our California assets she reorganized the business and changed its processes so it would be stable in a wide range of product prices.

She has built our Permian Resources business into a sustainable, profitable growth engine for OXY.

She is an accomplished team builder and has the confidence of executives and employees throughout the business.

She also has had the misfortune of officing next to me for the last couple of years.

The Board, of which I am a part, has worked on this succession plan for the last two years.

The directors interviewed a number of executives and considered both internal and external candidates.

In the current volatile business climate, our view is that an experienced successful executive who knows our business well is the best choice.

You will find Vicki to be a thoughtful, engaging agent of change for OXY.

Yesterday we also announced a dividend increase of just over 4%.

This is our 13th consecutive year that we've raised our dividend.

We carefully considered our future capital needs and likely cash flows.

Our current estimates are that we should be able to continue to grow our dividend for many years into the future.

The new ethylene cracker which comes on in 2017 provides a substantial boost to distributable cash from our already important Chemical business.

Our base oil business in Abu Dhabi, Oman, and the Permian EOR will all support our cash flow and grow modestly over time.

Without profitable growth, the Company will not prosper.

High rates of growth and cash flow and profits will come from our Permian Resources business.

We remain mindful of the need to pay close attention to drilling for profits, not just volume growth.

Our overall financial strength gives us confidence that we will be able to spend what we need at a range of product prices and still grow our dividends.

I would like to lay out or goals for 2015 and how we have planned to adjust to lower commodity prices.

Our principal goal for the year is to achieve cash flow neutrality where our operating cash flow covers our capital spending and dividend outlays by the fourth quarter of this year at around $60 per barrel oil prices.

We will achieve this goal through deploying our capital and operating cost savings into further production and cash flow growth, driven mostly by our Permian Resources segment and the startup of the Al Hosn gas project.

Year-to-date we estimate that about $400 million is in captured cost reductions.

We expect our 2015 capital outlays to be less than our $5.8 billion budget and some of the savings will be redeployed into Permian Resources.

In short, we are learning to do more with less and expect continued improvement in productivity through the year.

The Permian Resources segment has made considerable progress over the last six months, improving our capital efficiency.

As slide 6 illustrates, we have at least 16 years of inventory with returns that exceed our cost of capital at oil prices less than $60.

Through continued reduction in drilling and completion costs and improvements in productivity we will lower our finding and development costs and increase our inventory of well locations with returns that exceed our cost of capital.

In addition to improved capital efficiency, we expect to see improvement in our cash operating costs with reduced workover activity, lower energy costs, and a larger base of production.

This improved cost structure gives us confidence in driving production growth.

In the first quarter of 2015 we grew US oil production by 9,000 barrels a day, a 5% gain quarter over quarter and 14% year over year.

Production growth was driven by our Permian Resources assets, which produced 98,000 BOE a day in the first quarter of 2015, a 46% increase year over year.

Oil production growth in the Permian Resource was even stronger with a 25,000 barrel a day increase year over year.

Given the strong start to 2015, we are increasing our full-year guidance for the Permian Resources segment from 100,000 BOE a day to 105,000 to 108,000 BOEs per day.

The Al Hosn gas project started up in January with one train online.

During the startup process, production was curtailed to modify the sulfur and NGL processing units.

These adjustments were completed in late April and the plant was restarted.

We expect to ramp up production through the second quarter and to average (technical difficulty) we expect production of 35,000 BOE a day with the plant running at full capacity in the second half of the year.

Despite a lower capital program, we expect production growth of 60,000 to 80,000 BOE a day in 2015, driven by a startup at the Al Hosn gas project and the focused development program we will run in our Permian Resources segment.

In the United States we expect oil production growth of about 8%, partially offset by declines in NGLs and natural gas production.

Vicki Hollub will provide further details on the outlook for the US Oil and Gas business.

As we capture price savings from suppliers and improve the efficiency of our operations, we are able to do more with less spending.

Our capital run rate in the first quarter was higher than the $5.8 billion full-year level and will decline through the year.

Given our large acreage position and deep inventory, we have the flexibility to defer drilling and appraisal activities.

Although we will likely outspend our cash flow in the first half of the year, we expect that by the fourth quarter our operating cash will cover our capital expenditures and dividend payments, assuming a $60 per barrel oil price environment.

We have approximately 69 million shares remaining on our current share repurchase authorization.

We will continue to repurchase shares subject to stock price and market conditions and expect to ultimately repurchase the entire amount.

Now I will turn the call over to Chris Stavros for a review of our financial results.

Thank you, Steve, and good morning, everyone.

We generated core income of $31 million for the first quarter of 2015, resulted in diluted earnings per share of $0.04, a decrease in both the year-ago quarter and fourth quarter of 2014.

The decline in core earnings is primarily due to lower commodity prices for all products.

Our realized oil price for the first quarter of $48.50 a barrel was down about $23 a barrel sequentially.

US natural gas prices also declined, down more than $1 to about $2.50 per MCF.

NGL prices also fell sharply to just under $18 a barrel in the first quarter, down about 35% from last year's fourth quarter.

In response to the current price environment, we have aggressively ramped down our capital program, focusing our development activity in our core areas of the Permian Basin and parts of the Middle East, with an emphasis on growing our production volumes more efficiently.

We have also renegotiated many of our supplier contracts, which should result in meaningful savings this year, which Steve outlined.

The combination of reduced drilling activity, the wind down of spending for the Al Hosn project, and improved well cost efficiencies resulted in our total capital spending falling to $1.7 billion in the first quarter from $3 billion in the fourth quarter of last year.

As Steve noted earlier, we expect to be running cash flow neutral after capital spending and payment of our dividends by the fourth quarter of this year at oil prices of roughly $60 a barrel.

Despite the cut in capital, we continued our strong domestic production growth generated from our Permian Resources assets.

Permian Resources grew its oil production 68% in the first quarter, adding 25,000 barrels per day compared to the year-ago period, with total BOE growth of 46%.

Permian Resources oil production improved by 11,000 barrels per day, or 22% sequentially, to 62,000 barrels a day in the first quarter.

Turning to the specific business segments, Oil and Gas core after-tax earnings for the first quarter of 2015 were $109 million, $259 million lower than the fourth quarter of 2014 and $851 million lower than last year's first quarter.

For the first quarter of 2015, total company Oil and Gas production volumes averaged 645,000 BOE per day, an increase of 29,000 BOE in daily production from the fourth quarter and 7 BOE per day from the same period a year ago.

As I mentioned earlier, our first quarter of 2015 worldwide realized oil price fell sharply, declining by 32% and 51% compared to the fourth and first quarters of last year.

After-tax core results for our domestic Oil and Gas operations were a loss of $89 million, compared with income of $59 million in the fourth quarter of 2014 and income of $412 million in the first quarter of 2014.

Results on both a sequential and year-over-year basis at our domestic operations were severely impacted by much lower realized oil prices and to a lesser degree lower NGL and natural gas prices.

The negative price impact was partially offset by lower DD&A rates and higher crude oil production volumes for both comparative periods.

Total domestic Oil and Gas production averaged 326,000 BOE per day during the first quarter of 2015, up 5,000 BOE per day sequentially and 24,000 BOE per day on a year-over-year basis with substantially all of the increase coming from Permian Resources.

Domestic oil production was 198,000 barrels per day during the first quarter of 2015, an increase of 9,000 barrels per day from the fourth quarter and 25,000 barrels per day from the year ago quarter.

International after-tax core income was $200 million for the first quarter of 2015, compared to $355 million from the fourth quarter and $553 million from the same period last year.

The decline for both periods was driven by lower realized oil prices.

International Oil and Gas production volumes rose by 24,000 BOE per day on a sequential quarterly basis to 319,000 BOE per day in the first quarter of 2015.

Approximately half of the increases to production, both year-over-year and sequentially, resulted from lower prices affecting our production sharing contracts.

Commencement of production from the Al Hosn gas project added 9,000 BOE per day in the quarter.

Production at Al Hosn for the quarter was less than anticipated as during the startup of production -- during the ramp we experienced some commissioning-related issues on the sulfur recovery units.

Modifications have now been made and we anticipate reaching full productive capacity at Al Hosn over the coming months.

Our Oil and Gas cash operating costs fell to $13.36 per BOE for the first quarter of 2015 compared to $14.18 from the fourth quarter of last year, due to the benefit of higher production and lower energy costs.

DD&A for the first quarter of 2015 was $15.35 per BOE, compared to $18.09 per BOE during the fourth quarter.

Taxes other than on income, which are directly related to product prices, were $1.63 per BOE for the first quarter of this year compared to $2.45 per BOE for the full year of last year, 2014.

Our first-quarter exploration expense was $8 million.

Chemical's first-quarter 2015 pretax core earnings were $139 million compared with $160 million in the fourth quarter and $136 million in the same period a year ago.

The sequential decrease in earnings primarily reflected lower prices for most product lines and lower caustic soda volumes, partially offset by lower ethylene and natural gas feedstock costs.

Midstream pretax core results were a loss of $5 million for the first quarter, compared to income of $168 million in the fourth quarter and $96 million in the same period a year ago.

The decline in results for both comparative periods was caused by several factors including lower marketing margins as a result of tighter Midland to Gulf Coast crude oil differentials; lower gas plant income, which reflected sharply lower NGL prices; lower pipeline income due to a turnaround at the Dolphin Plant; as well as lower third-party gas sales, combined with the impact from our reduced ownerships in the Plains Pipeline GP after the fourth-quarter sale of a portion of these units.

Our cash flow from continuing operations before working capital changes was approximately $1.1 billion for the first quarter of this year.

During the fourth quarter of 2014, our crude capital spending and operating expenses were based on a work program that was significantly higher than the first quarter of this year.

As we ramped down activity in the first quarter, our capital accruals declined and our net working capital declined.

We used about $1 billion in the first quarter of 2015 for payments related to the higher capital and operating expenses that were accrued at year-end 2014.

As we continue to reduce activity in the second quarter, we expect to see further working capital usage as we reduce our accounts payables.

However, we expect this to be at a lower rate.

This trend is normal in a commodity down cycle and one that we would expect to dissipate by the third quarter as we reach a more stable level of capital spending.

Should we see a continued recovery in crude oil prices and increase our drilling activity, we would expect this trend to reverse and see positive working capital movements.

Total company capital expenditures for the first quarter of 2015 were $1.7 billion and we expect our quarterly expenditures to continue to ramp down through the year.

Oil and Gas spent $1.5 billion with Permian Resources expenditures comprising nearly 50% of the total with the remaining $200 million split about evenly between Chemicals and Midstream.

Based on our lower pace of spending in the first quarter and continued cost efficiency gains, we expect our total capital spending for the year to be below our original guidance of $5.8 billion.

Our fourth-quarter 2015 exit rate of capital would imply an annualized spending level of approximately $4 billion.

We paid cash dividends of $557 million in the first quarter and purchased [2.7 million] of our shares for $207 million.

Our cash balance at the end of the first quarter of 2015 was $5.4 billion.

As a reminder, we currently hold shares in the Plains GP and California Resources Corporation with an aggregate value of about $3 billion.

With respect to CRC, we continue to own 71.5 million shares currently valued at about $600 million.

We are required to dispose of all of these shares within approximately a year through either a dividend to our shareholders or in an exchange for either OXY shares or debt.

Our debt to capital ratio was 17% at the end of the first quarter 2015.

The worldwide effective tax rate on our core income was 75% for the first quarter of 2015.

The increase in the rate reflects a higher proportion of international income for the first quarter.

With respect to our Oil and Gas production, domestically we expect our oil production for the second quarter to grow by 5,000 barrels per day with the increase coming from Permian Resources.

Permian Resources is expected to grow its overall volumes by more than 7,000 BOE per day in the second quarter.

Our Mid-Continent gas production is expected to decline from first-quarter levels, resulting in an overall domestic sequential growth rate of at least 4,000 BOE per day.

We expect our international production volumes to increase by about 15,000 BOE per day in the second quarter.

The increase should come primarily from improving production rates at Al Hosn, which we expect to be about 25,000 BOE per day, and offset by the loss of production in Yemen due to the civil unrest and security issues in the country.

Although the contract in Yemen was set to expire at the end of this year, we anticipate no further production volumes from the country in 2015.

For reference, Yemen contributed approximately 9,000 barrels per day in the first quarter.

As Steve mentioned in his opening remarks, we have raised our full-year 2015 guidance for production growth to a range of 60,000 to 80,000 BOE per day, an increase of 20,000 BOE per day versus our previous guidance.

We expect full-year production in Permian Resources to be in the range of 105,000 and 108,000 BOE per day, a year-over-year increase of more than 40%.

Overall domestic volumes are expected to increase to over 325,000 BOE per day, at least 5% higher than 2014.

Internationally we expect full-year volumes from Al Hosn to be approximately 35,000 BOE per day.

Should oil prices move higher, our production volumes could be negatively impacted by our production-sharing contracts.

Price changes in current global prices affect our quarterly earnings before income taxes by $30 million per $1 per barrel change in oil prices and $7 million for $1 per barrel change in NGL prices.

A swing of $0.50 per million BTUs in domestic gas prices affects quarterly pretax earnings by about $15 million.

Our second-quarter 2015 exploration expense is anticipated to be about $35 million pretax.

We expect our second-quarter 2015 pretax Chemical earnings to be about $185 million and second-quarter Midstream earnings should be in the range of $100 million pretax as we anticipate higher gas sales from the Dolphin Pipeline and improved marketing margins as a result of wider inland versus Gulf Coast crude oil price differentials.

We expect our interest expense to rise to about $42 million in the second quarter from $28 million in the first quarter as the start of Al Hosn reduces our capitalized interest.

Using current strip prices for Oil and Gas, we expect our 2015 domestic tax rate to be 36% and our international tax rate to remain at about 65%.

To summarize, we have demonstrated strong year-over-year production growth of nearly 13% in the first quarter, bolstered by our Permian Resources unit.

The performance of this business, combined with growing volumes from Al Hosn, provides us with confidence to raise our guidance on 2015 production growth.

We expect a growth in our volumes combined with the reduction in our capital spending and improving efficiencies to lead us to a cash flow-neutral position by the fourth quarter at oil prices of around $60.

I will now turn the call over to Vicki Hollub, who will provide an update on our operations in the Permian Basin.

Thank you, Chris.

Today I will first review the highlights of our Permian Resources and Permian EOR activities in the first quarter and then I will provide guidance on our program for the remainder of 2015.

I'd like to highlight a few key messages.

First, Permian Resources performance is exceeding expectations.

Second, our core Permian unconventional programs generate strong returns in the current environment and we believe that it will get even stronger through our focus on execution excellence.

Finally, our Permian portfolio is unmatched in the industry.

The combination of our assets in Permian Resources and EOR, along with the expertise and commitment of our teams, will allow us to grow the business and live within cash flow in a $60 oil environment.

In the first quarter, Permian Resources achieved daily production of 98,000 BOE per day, which is a 17% increase from the 84,000 BOE day that were produced in the fourth quarter and a 46% increase versus the prior year.

With regard to oil, we produced 62,000 barrels per day for the first quarter.

This is a 68% increase from a year ago and a 22% increase from the previous quarter.

We would have achieved even higher production, but were negatively impacted by approximately 4,000 BOE per day by winter weather events in January.

During the first quarter, our capital expenditures were $728 million.

We operated 25 rigs and drilled 86 wells, including 61 horizontal wells.

We placed 126 wells on production, including 67 horizontals.

This is an increase of 20 horizontal wells from the previous quarter.

At the end of the quarter, 16 wells were on flow back and 48 were not yet completed.

Permian Resources has a large inventory of profitable wells to develop in a low price environment and we are successfully impacting four actions that are reducing the economic hurdle point of our inventory.

First, we are investing in reservoir characterization and optimization to improve well productivity.

Second, we are applying enhanced manufacturing principles to improve time to market and reduce costs.

Third, we are aggressively working with our suppliers to lower costs.

Lastly, we are enhancing base management and maintenance operations to maximize production at minimal operating cost.

In the fourth quarter of last year, we began transitioning from appraisal mode to a targeted development program utilizing a manufacturing approach combined with integrated planning and engineering.

This has reduced nonproductive time; maximized the efficiencies of pad drilling, including the use of zipper fracs; and has reduced infrastructure costs.

As a result of these efforts, we have achieved significantly improved bell delivery in well costs.

In the Delaware Basin, our Wolfcamp A 4,500-foot well cost decreased by 24% from 2014's cost of $10.9 million to a current cost of $8.3 million.

We reduced our spud-to-rig release time by 17 days from 2014's average of 43 days to March's average of 26 days.

In the Midland Basin, we reduced the cost of our Spraberry 10,000-foot wells by 19% from 2014's cost of $9.7 million to a current cost of $7.9 million.

In New Mexico, we reduced the cost of our Bone Spring wells by 14% to $5.7 million.

These reductions were achieved by implementing design enhancements such as two-stream casing designs, optimizing bottom hole assemblies and bits, utilizing drilling dynamics to improve rates of penetration.

Additionally, we have continued to achieve reductions in our commercial rates.

Based on the results achieved so far, we are confident that by the end of this year we can achieve an average well cost that is 20% to 25% lower than in 2014.

In the Delaware Basin, we have currently identified 4,600 horizontal development locations.

We have 1,500 horizontal locations ready for development, including 800 sites in the Wolfcamp A bench.

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

In New Mexico, our Bone Spring potential is equally as significant with 1,500 potential locations.

In the Delaware in Q1 we operated 10 horizontal drilling rigs and two vertical rigs.

We drilled 45 wells and placed 64 wells on production.

In Barilla Draw, we placed 18 horizontal wells on production in the Wolfcamp A benches.

These wells achieved an average peak rate of 1,371 BOE per day and a 30-day rate of 1,017.

In the last call I discussed the Peck State 258#6H well, which achieved a 30-day rate of 1,760 BOE per day.

I am excited to report this well is still producing over 1,000 barrels of oil per day after four months of production.

We continue to achieve encouraging results with our efforts to improve landing zones, optimize cluster spacing, and increase sand and concentrations.

For example, our Eagle State 28#6H well achieved an average peak rate of 2,037 BOE per day and 30-day rate of 1,470 BOE per day.

Additionally, our Peregrine 27#8H well achieved average peak rate of 1,768 BOE per day and a 30-day rate of 1,309 per day.

In New Mexico, the performance of our Bone Spring wells continues to exceed our expectations.

Recently our Cedar Canyon 15 Federal-5H was placed online with an average peak rate of 1,322 BOE per day and a 30-day rate of 1,127.

In the Midland Basin, we've currently identified 2,500 horizontal well locations with 1,050 in the Spraberry and Wolfcamp A and B benches.

In the first quarter here we operated 11 horizontal drilling rigs and two vertical rigs.

We drilled 41 wells and placed 62 wells on production.

Now I would like to update you on Merchant, which is a new area in the Midland Basin that we mentioned last quarter.

We launched into development mode early in this area and are drilling multiwell pads along with zipper frac completions.

Our Wolfcamp A and B have achieved an average peak rate of 1,408 per day, a 30-day rate of 1,145, and a 60-day rate of 844.

Our current well cost is $7.9 million, but we expect to lower it to $6.9 million as we move forward.

The Merchant 1411A well that we discussed last quarter achieved six months cumulative oil production of 100,000 barrels and equivalent production of 108,000 BOEs.

I would also like to provide an update on our Permian EOR business, which provides a stable and low decline base to our production at an advantaged cost.

As we discussed last quarter, our Permian EOR business remains profitable in the current downturn and we are continuing to make investments in these projects that significantly increase oil production from our portfolio of large conventional reservoirs.

The EOR business is expected to generate free cash flow this year, even in the current oil price environment.

Continued investment in these long-lived projects during the current market will result in more efficient construction costs which will yield a strong base for future growth and resources.

During the first quarter, we authorized the first portion of the North Hobbs Phase 2A expansion project.

The project will develop 13.7 million BOE of reserves for a development cost of $13.82 per BOE.

The Phase 2 project builds on the success of the North Hobbs Phase 1 project, where CO2 flooding has added a sustained 5,300 barrels of oil per day that had a peak of 7,000 barrels of oil per day to the unit's production since the project began 12 years ago.

Another significant EOR project currently in progress is the Denver Unit Battery 5 redevelopment which will yield 21 billion BOE of net reserves for a development cost of $4.80 per BOE.

This project is typical of many opportunities to develop and comingle both the main oil column and the residual oil zone in the same wellbore.

The Battery 5 project includes the deepening of almost 150 main oil column producing wells to the residual oil zone.

Year-to-date EOR is ahead of plan and meeting our aggressive cost improvement targets, which includes a $65 million reduction in well maintenance.

By applying manufacturing concepts to well repair, we have reduced our rig hours per repair by 20%.

This is allowing us to reduce operating costs while maintaining our base production.

In closing, we will continue to execute a focused development in 2015 and we will also continue to pursue step changes in well productivity and cost structure.

For the remainder of 2015 we plan to operate an average of 13 drilling rigs to drill 150 wells in Permian Resources.

This is a higher activity level than previously planned, but we believe investing the efficiency gains is the prudent action to take.

As Chris said, we expect to produce an average of 105,000 to 108,000 BOE per day in 2015, which exceeds our previously-stated target of 100,000 BOE per day.

Strong production growth from our Resources business along with a high volume, low capital intensive EOR business keeps us well positioned to not only meet the challenges of this lower price environment, but also to profitably grow our combined Permian businesses.

Now I will turn the call back to Chris Degner.

Thank you, Vicki.

I think we will now open the call up for questions.

(Operator Instructions) Doug Leggate, Bank of America Merrill Lynch.

Thanks.

Good morning, everybody, and, Vicki, congratulations.

It's nice to get that issue behind us.

Looking forward to seeing what you're going to do next.

I guess I've got two questions, if I may.

The first one is the Al Hosn guidance.

I just wondered if you could explain the difference between what you suggested at the beginning of the year and what you are looking at now in terms of the reduction in full-year expectations.

Then I've got a follow-up, please.

Doug, this is Sandy Lowe.

Plants started up and we have 25% sulfur recovery there.

Some of the sulfur units weren't working quite properly, so we took them offline, made some modifications.

Today the plant is back up to 45% of production, which is about 25,000 BOEs to us and we should be back up at peak production of 1 billion a day -- 1 million a day, sorry, at the end of the month, beginning of next month.

So the guidance, as given already by Chris, should be good for the year.

I guess I had a couple of other issues I was going to touch on, Sandy, but taking advantage of you being there, maybe I will make my second one on your region, if I may.

There has been a fair amount of chatter around both the ADNOC concessions; obviously, the slowdown it seems in terms of asset monetizations in the region, and finally the prospect of extensions in the Oman contracts.

I'm just wondering if you could give us a kind of general update as to how those things stand, and I'll leave it there.

Thank you.

Well, I can guide you only as to what you see in the press on the ADNOC concessions.

Everybody who is involved is still bound by a confidentiality agreement.

The press has been reasonably forthcoming in that respect.

As far as asset monetization, well, you know, when the price of oil dipped like it is, we have kind of two issues, that people want to pay less for it and also they don't have quite as much money to get into it.

So things are somewhat held in abeyance at the moment in that regard.

And the last question I believe was about Oman.

We are in discussions at the moment.

We are not at record-breaking production in our Block 9, which is the one under discussion and of over 100,000 barrels a day, so everybody is happy with that.

So we're just ironing out the details of a new contract with the government.

Any timeline, because I believe that contract expires this year, Sandy?

So what's the prognosis if you don't get it done in the next six months?

I don't think there will be an issue with that, so it will be -- if it weren't quite complete, I'm sure they would extend us.

All right.

Steve, maybe I will squeeze just one more in, given that you jumped in there.

The pace of buybacks, given that your stock has lagged, I'm just curious on your thoughts process and then I will leave it there.

Thank you.

You know, we continue to buy the stock back on weakness, and so you should expect that we will return -- we will buy back shares over the next year or so and eventually get to our target.

The exact date or exact number each quarter is just hard to tell.

All right.

Thanks a lot, everybody.

Evan Calio, Morgan Stanley.

Good morning, guys, and congratulations as well to Vicki.

My first question is a strategic question.

Oxy was in the midst of a restructuring and successfully unlocking value prior to the cycle turn, and to position you well with large cash position into this downturn.

I know there's some leadership transition here yet.

How has the cycle changed your restructuring outlook?

I know you just mentioned the MENA asset divestiture or partial divestiture, but does it alter your view as it relates to Midstream or Chemicals?

And given the balance sheet, does it change your willingness to add resource and accelerate that shift here?

That is sort of a complicated question.

The downturn, the cycle of course -- we expect, if it stays volatile, whatever that means, we would expect opportunities to show up during the cycle.

Either to repurchase our stock or to buy other assets, just depending on what's going on.

Right now the asset market is quite expensive, so there's no reason to believe we will do much of that.

As far as the Middle East assets are concerned, they fall into two classes of assets, those that are where we have already spent the money and we are clipping coupons, which seemed fairly attractive in a more volatile oil price environment, and those that are more volatile and follow normal trends, which seem less attractive in this environment.

So I think that is where we are.

Some of those assets require some work and probably in the end divestiture or discontinuation of work there.

As far as the Chemical business is concerned, the Chemical business, once the ethylene cracker is on and the business becomes fully integrated with ethylene, its cash flow will be substantially larger than it is now.

And I think that would be the appropriate time to look at whatever makes sense to do.

I think if you do it too early you are going to wind up undervaluing the asset.

So I think we are a couple years away.

Of course, I will be watching that from the beach, but --.

And so you could ask Vicki at the time what she wants to do.

Great, that's helpful.

Maybe just different question that is I guess the reverse direction in which we were just headed.

Prior to the downturn you discussed going to 54 horizontal rigs in the Permian by the end of 2016.

You're at I think 21 active now.

I know you just de-ramped, yet how are you approaching a potential re-ramp in activity given your potentially higher long-term goals?

Is it -- is incremental free cash flow how you will drive that rate of incremental spend?

I'm going to answer first, and then we will let Vicki answer.

You might get two different answers.

But I think, generally, the most attractive asset we have in almost any product price environment is the Permian business.

Maybe some of the EOR business, but also in the resource business.

Any money we have that is excess is going to wind up there.

We have already -- I think Vicki mentioned it; we have changed a number of rigs were we are going to run by the end of the year.

We are still looking at that.

We got a lot of locations that work in a $60, $65 environment.

If we start a well today, we won't see the production really until late in the third or the fourth quarter.

And we've gotten a lot better at bringing the stuff to market faster because the times have really shortened.

That's why we are having a hard time keeping up with our estimates.

I think our estimates are still -- have room.

But I think what we're going to try -- so we may put some more rigs to work, depending on the environment.

Our view on this is different than maybe some others.

You get -- if you put the stuff on production, these laws work.

There's no issue about the returns or whatever.

If oil prices move up, you will get 90%, 95% of that change in that well because you have a little bit of production this year so oil prices are higher next year.

You are going to get 90% of that.

I think this -- if there is a boost in prices, I think at the end completion costs will start to rise, not fall, so we may be at the part where you want to finish the wells.

I don't -- we've got a lot of locations, we got thousands of locations.

Any locations that you put off for now you've delayed drilling for 10 years from now effectively, because you've moved them to the back of the line.

So our view is that you drill through this environment; you reap the returns that are there now.

Oil prices move up, you are going to get the bulk of that.

I think delaying your production, because you would know what oil prices are going to be next year, seems to me to be --.

If people do know, I wish they would send me an email so I could get rich.

I think I will go with what Steve said.

But just to build on that, I'd like to say that we are certainly keeping our team intact and ensuring that everybody has the resources necessary to prepare us to be able to maximize our flexibility.

We are continuing to work on development plans in the areas that are not our core areas, because there's certainly a lot of opportunities where, with increased prices, we could start to ramp up and have lots of opportunities available beyond the core areas we are currently developing.

So what we are doing is laying out those plans, evaluating those, and starting to go ahead and permit just so that we can -- if prices do go up, we can ramp up rigs more efficiently than we have in the past.

Just one last, is there any comment on an optimal pace to retain your -- the efficiencies that you are realizing today?

That's what -- one of the things we're trying to do is make sure we maintain a minimum level of rigs in order to continue improving our efficiency, because you make a good point.

You can't really get efficient if you're not actually out doing the work and that's one thing that has provided us a lot of benefit here.

In all the areas that we have continued operations, as you have seen on the charts, we've gained significant efficiencies.

And at Merchant where we -- that is kind of a new startup.

We don't have those efficiencies yet, but we are starting to see those coming as well.

So we think it's critically important to maintain a certain level of activity with not only rigs but the frac companies that you are using and the other service providers as well.

Great, thanks.

Guy Baber, Simmons & Company.

Good morning, everybody.

Congrats on a nice quarter, and Vicki, congratulations to you as well.

My first question was on cost structure, but obviously you have been very successful in reducing your cost structure in recent months.

You mentioned $400 million in savings.

Can you discuss where you are in that process, where you see that number potentially going?

And then if you could also just discuss for us how much of that you see as structural and permanent versus temporary, and what might reverse when prices begin to rise again.

Just trying to understand how that outlook might be structurally improving on the cost front.

And then I have a follow-up.

The cost structure that we are trying to get to is we currently have some of our contracts with suppliers tied to oil prices, so some of those contracts will go up with the oil prices.

However, the majority of our contracts for the drilling rigs and for our frac providers are not necessarily tied to an oil pricing index.

So what we're really trying to do is get more efficient and we expect that the cost structure that we are going to achieve by fourth quarter is going to be one that does have some exposure to flexibility in prices, but I don't believe that more than 60% to 70% of our cost structure improvement will be associated with oil price changes.

Okay, great.

Then I had a follow-up on -- I wanted to talk a little bit more about the Permian and capital allocation, but obviously results in the Permian have improved very rapidly and considerably just in the last six months or so.

So the question is does that rapid improvement really change your view of capital allocation relative to what you would have thought six months or a year ago?

Meaning are you much more likely now to commit incremental discretionary capital to the Permian, or perhaps even look for acquisition opportunities and bolt-ons as opposed to the buyback versus one year ago?

Just hoping you can elaborate on most recent thoughts there and what those improvements to the Permian really mean.

Well, the Permian is obviously doing well and we continue to put what is prudent into it.

And we will continue to focus on it.

But as it generates better results it generates more cash, and that cash, the bulk of that we reinvest it and continuation of that as long as it does what it's currently doing.

Fracs are -- the reason we sort of are running ahead of our outlook was simply because we didn't think we would be quite this good.

And we continue to run ahead of outlook in our plans, so I think there's still room there.

I think the buyback question is quite a different one.

We need to reduce the number of shares outstanding over time and we will do that.

But just as important, we need to increase our cash flow so that we can continue to have more free cash flow to -- for dividends and share repurchases.

That is really -- the purpose I think at the very beginning I said you have to focus on the fact that you can't just save and cut back and that's going to make it better.

If you don't invest and you start to decline, you are going to have a hard time recovering from it because you have a decline curve and you're declining against it and you're starting up again.

So our objective is to continue to grow the volumes through the year and to the extent we can unless you get a collapse in product prices.

And then the free cash flow that will generate over the next year can be used to enhance the dividend or repurchase shares.

That's very helpful.

Thanks for the comments, Steve.

Ed Westlake, Credit Suisse.

Congratulations, Vicki.

Two questions, again on the Permian.

It's probably going to be a theme.

You have a great slide in the deck just in terms of drilling days and getting from your 26 days down to a target of 16.

What is the key thing you are doing differently?

Is it just as simple as just getting to an efficiency mode or are there other things you need to do to get to the best in class?

And then I've got a question on completions.

In terms of the drilling days, one of the things our team is doing is they are taking an evaluation of the formations that we are drilling through and modeling what it takes in terms of the weight on our bit and rotation of the bit to really design exactly how much we should do.

How fast we should rotate the bit and how much weight we should put on it by interval.

It's a process that is called mechanical specific energy and that's one of the processes that has helped us to significantly reduce our drilling days.

That along with the fact that we are better managing our mud systems and we have seen a lot of improvement there.

We are seeing significant reduction in nonproductive time during our drilling operations.

And part of that, a good part of the nonproductive time reduction is due to the efficiencies of our teams and the scheduling.

Some of that is due, as well, to the fact that the Permian is not as stretched in terms of the support system now that activity is lower.

So it's a combination of a lot of things, but the thing I am most excited about is the engineering that our teams are doing on the wells and that is sustainable.

So the drilling day reduction is one of the things from a cost structure standpoint improvement.

That is sustainable and that -- we haven't been able to apply that everywhere yet.

Like in Merchant that's one of the things that is going to help us to further improve our drilling efficiency in Merchant.

It is really based on some incredible work by our teams, especially with respect to the engineering aspect of what we are doing.

Then my second question on completions.

I was down at the Offshore Technology Conference, which they may as well call the onshore and offshore technological conference, and obviously there's a lot of new technology.

Give us a sense of any pilots or new solutions which you see driving the EOR improvements or lowering the cost?

One of the things that we have been trying -- and we are not prepared yet to talk about the results, but we have used several different techniques to isolate how we inject and place our proppant within the horizontal section of the well.

And we feel like that is the next area that we feel has the most opportunity for improvement.

And that is getting the most contact with your proppant through the formation, so it's getting the most surface area contact in order to create the conduits through the wellbore.

What we felt is that if we could isolate our stages with just single clusters, rather than two to three to four clusters per stage, that we could more efficiently frac the formation.

So we've tried some of that and we've tried various types of tools to help us do that.

We are in the process of evaluating those results now and hope to have some things that we can share in the next three to six months.

Thanks very much, good luck.

Ryan Todd, Deutsche.

Thanks and congratulations, Vicki.

Maybe another follow-up question on the Permian.

You have some slides in there that update on well cost inflation in the Permian.

Can you -- with a 2014 level, a current level, and a target level, I guess can you talk a little bit about where the current level of well costs are relative to what you implied in the 2015 budget?

And then is the target well cost kind of a year-end 2015 target?

Is that an eventually full-blown development program target?

Can you maybe talk a little bit about -- and how much of that is from service cost deflation versus improved efficiencies?

The target that we are trying to achieve, we already have achieved that with some of our wells, so the current cost where I am saying we are there that's basically an average of what we are seeing.

That is -- actually our plan numbers were a little bit higher than certainly what our target is and sort of in between our target and our current.

But in terms of where we expected to be for Q1, we are ahead of schedule because we are implementing these things as we go.

And so the target was where we expect to be by year-end, but we think will be ahead of that.

Great, that's helpful.

And then it's not -- I don't know if you -- you addressed costs a little bit earlier and I wasn't clear whether you addressed this point or not.

Last quarter you had a target of $500 million of cost savings.

You said you captured $400 million to date.

Any update on whether you expect greater than $500 million at this point or is that still a reasonable target for the year?

It's Steve.

I think it's a reasonable target for the year.

I think we will sort of get there, but I think it's -- it could be more than that, but I think right now we will stick with that.

Great, I appreciate it.

I'll leave it there.

Roger Read, Wells Fargo.

Good morning and congrats, Vicki, on your new role there.

Kind of coming back around to the Permian Resources for the obvious reasons.

As you talked about guidance and being in a situation where you could potentially still exceed that, can you quantify at all how much of that is the well performance issues that you highlighted earlier in terms of IP rates and 30-day rates and how much of it is just executing on getting the wells in the ground, sort of that if you spud today whether or not you can get it started late Q3 or if it slides well into Q4?

Currently, it is principally a performance execution.

It's accelerating the well delivery.

However, we do have a couple of areas where we are seeing improved performance.

You'll notice that the graphs on the Delaware Basin, we are still seeing strong performance versus our peers in the Wolf Bone and the Barilla Draw area.

There are other areas where we are seeing improved performance in terms of our program design.

We're still seeing opportunities to increase our per-well performance and we are seeing -- and the main thing we are doing there is targeting better landing zones.

So I would say that right now, just to go back and bottom-line answer the question, it's incredible execution on the part of our teams to get the wells on faster and part of it is a little bit of improved recovery on a per well basis.

But we still expect there will be more of that to come.

Okay, thanks.

And then Yemen, as you said earlier, that was going to go away anyway.

But I was wondering what was the, I don't know, margin or cash margin per unit that impacts you?

I don't remember.

Chris has got it.

It was generating about $15 million a quarter after-tax, if you want to think about it that way.

Okay, appreciate it.

Thank you.

Paul Sankey, Wolfe Research.

Good morning, everyone, and congratulations, Vicki.

Steve, you start your slides in a differentiated way with talk about dividend growth.

And I think -- and I assume Vicki will continue this as the primary ultimate aim of OXY.

Can you square the circle because, as I said, that's a differentiated strategy from most other, if not all other, US E&Ps?

Does it mean that you have better geology costs, lower growth?

How is it that you are going to be able to deliver a higher dividend growth than others in essentially the same place?

Thanks.

Well, most of them don't have any dividends so you are comparing against an environment with -- so we are sort of a tall midget here.

I think dividends -- if there is a religious activity here, I think that's that.

It provides discipline to the management.

Otherwise you print shares, do all sorts of wealth-destructive things.

The dividends give you discipline.

We have a more diverse business than the typical E&P.

We've got the sort of stable stuff that we have already spent the money on in the Middle East to generate cash.

We've got the Chemical business, which always generates cash.

We have a Midstream business which generates cash.

So it is -- and we have less debt relatively.

So all that provides more cash than the typical and what we do with the cash is we buy in some shares and we pay more dividends.

You have to have something that you can't be -- at our size you can't try to compete with somebody who makes 10,000 barrels a day in growth.

We think that our long-standing acreage position, that's also part of it as we didn't just acquire the acreage last month or last year.

We've got the EOR business, which generates a lot of cash.

In economic terms, those are called monopoly profits and that's really what you are seeing.

It's the same thing you see at the large integrateds, so that is what differentiates it.

The other guys have a different strategy.

Nothing wrong with their strategy, it's just different.

But we think the cash share will be strong and we invest -- sometimes unpopularly by the way and things that will generate a lot of cash for a long period of time.

And so we always are thinking about how we're going to grow the dividend.

I am -- she can speak for herself, but I think Vicki and Chris have the same basic belief, because they have been hearing it for a long time.

And that is -- Chris is planning on staying, so Chris will be your principal person to talk to about financial matters, but Vicki will certainly set the strategy.

I'm glad to hear that Vicki is not planning to fire Chris.

Could -- I guess theoretically.

Let's slightly skip over your politically incorrect comment and just say, assuming that you are not comping against other E&Ps, but I would assume on an above inflation rate of growth, right, otherwise you are not growing the dividend.

Would that mean that ultimately given that the assets that you listed are all more or less zero growth once we get through some of the project startups, would that mean that we align your long-term volume growth with your long-term dividend growth?

Yes, that's probably about right.

Which would be 5%-plus, but not 10% I guess?

It's hard to say exactly, because you got the Chemical business which is a little different.

And that is going to generate a sizable amount of free cash out here.

I'm sure it will generate $1 billion in free cash and so that will cover a fair amount of the dividend without doing anything.

And some growth there.

It's sort of a GDP grower when all is said and done on its cash flow.

(multiple speakers) So that provides the base and we just -- the dividends are the cost of keeping the shareholders.

It's cost of capital, however you want to say it.

And without that sort of discipline, you do all kinds of crazy stuff.

Yes, and just finally, would it be fair, if harsh, to say that the other element here is that you are coming off a lower base in terms of your operational performance in the Permian and that provides the potential for greater growth?

And I will leave it there.

I don't know, maybe.

But I think growth is growth.

We spent a lot of time building to this so that we wouldn't be in the same situation that a number of other companies are.

We spent money and time, and so we started the acceleration when we knew what we were doing -- mostly.

And that's really -- I think we told you that in the past, which nobody listened to.

Okay.

Thanks, Steve.

John Herrlin, Societe Generale.

Just a quick one for me.

Steve, nobody would accuse OXY of being a contra plastic, but regarding the Permian, you are going to drill in the Resources division I guess, Vicki, 150 wells.

Could you give me a sense of what the split would be Delaware, Central Basin, and Midland?

And that's it.

Of the 150 wells, none of them will be on the Central Basin platform.

It will be almost split half-and-half between the Midland Basin and the Delaware Basin.

Okay, great.

That's it for me.

Thank you.

Thank you.

This concludes our question-and-answer session.

I would like to turn the conference back over to Mr. Degner for any closing remarks.

Thanks, everyone, for participating.

I know it has been a busy day for you.

Please give us a call if you have any follow-up questions.

Thank you, sir.

Today's conference has now concluded.

We thank you all for attending today's presentation.

You may now disconnect your lines.