西方石油 (OXY) 2016 Q2 法說會逐字稿

Good morning and welcome to the Occidental Petroleum Corporation's second-quarter 2016 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, Laura. Good morning, everyone, and thank you for participating in Occidental Petroleum's second-quarter 2016 conference call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Jody Elliott, President of Oxy Domestic Oil and Gas; Sandy Lowe, President of Oxy International Oil and Gas; Chris Stavros, Chief Financial Officer; and Rob Peterson, President of Oxy Chem.

In just a moment I will turn the call over to Vicki Hollub.

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 results to differ is available on the Company's most recent Form 10-K.

Our second-quarter 2016 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 Vicki Hollub. Vicki, please go ahead.

Thank you, Chris, and good morning, everyone. Last quarter I told you our game plan for this year has been to address the things within our sphere of influence to ultimately, not only survive, but thrive in the current weak commodity price environment. To that end, we are on target to achieve the higher end of our production guidance for 2016, while keeping our capital program on budget at $3 billion.

We continue to make progress lowering our cost structure, which we know is critical to both short- and long-term success. Our capital discipline and cost reduction efficiencies, combined with improvement in UL productivity and better base production management, have enabled us to further reduce our total spend per barrel of production this year compared to 2015.

In addition, our strategy around capital is to be prudent and remain focused on returns, as we expect the commodity price environment to stay challenging through the rest of this year and into 2017. At the same time, we will maintain the flexibility necessary to maneuver through a range of price scenarios. Finally, due to the strength of our balance sheet and the quality of our portfolio, we have raised our dividend for the 14th consecutive year.

Total company production for our ongoing operations increased to 609,000 BOE per day from 590,000 BOE per day in the first quarter. The increase was driven by Al Hosn in Abu Dhabi and a new gas project in Oman. The increase in average daily production of 26,000 BOE per day from Al Hosn versus the first quarter of 2016 is due mainly to lower production volumes in the first quarter caused by a scheduled warranty shut down.

However, 10% of the increase is due to improved plant efficiencies gained by the Al Hosn operations team. As you know, Al Hosn gas is a joint venture between ADNOC and Oxy in Abu Dhabi. The Al Hosn team has done an excellent job of optimizing deliverability through the plant.

An additional 7,000 BOE per day came from Block 62 in Oman, where a recently-constructed gas plant was put online to process production from two newly-developed gas fields. The plant was completed on time and on budget. This enabled us to achieve record production in Oman this quarter.

In addition, our Qatar team has worked to get production in the Idd El Shargi South Dome field, or ISSD, to its highest level in over 16 years. Completion design improvements and complex horizontal wells and enhanced base production management contributed to this production milestone.

Permian Resources production this quarter was 126,000 BOE per day, representing year-over-year growth of 16%. As Jody will show, we are continuing to see improvements in well productivity in all areas.

The increases in production from Al Hosn, Block 62, and ISSD, along with strong year-over-year production growth from Permian Resources, will help us reach the higher end of our 4% to 6% production growth guidance for 2016.

Our capital spending in the second quarter declined modestly as we shifted timing on spending for certain chemicals and midstream projects and slowed our drilling program in the Permian. This drilling program is consistent with the plans we put in place at the beginning of this year and with our strategy to remain conservative in this price environment.

Continued improvements in project designs and capital execution have helped us to do more than expected with our $3 billion capital budget. These, along with improved production performance in many areas of our operations, are they reasons we expect to achieve the upper end of our production guidance for the year.

It is important to note that most of our cost reductions are due to our own efficiency gains, not service company unit cost reductions. In fact, approximately 80% of our drilling cost reductions are due to faster penetration rates achieved by the application of Oxy drilling dynamics, along with improved well construction design, lower cost of materials, and enhanced logistics.

In Permian Resources, the cost savings we have achieved due to improved efficiencies will be redeployed into drilling incremental wells in the latter part of the year, which will positively impact 2017 production. Additional capital will also be shifted to Colombia where our teams have generated opportunities that deliver attractive returns at current prices. This activity will also support 2017 production.

The construction of the joint venture ethylene cracker at Ingleside by OxyChem is on budget and on schedule to be completed in the first quarter of 2017. In addition, the crude oil export terminal at Ingleside being constructed by Midstream is also on budget and on time to be completed by year-end. The terminal will have a total oil storage capacity of 2 million barrels and throughput capacity of approximately 300,000 barrels of oil per day.

Although these activities will slightly increase our capital spending during the third and fourth quarters, we don't expect to exceed our $3 billion budgeted spending for the full year. With completion of the long-term projects in both our chemical and midstream segments we expect to have increased flexibility with our capital program in 2017.

Our efforts to focus on efficiency are paying off as we continued to lower our total spend per barrel of production. This metric includes our overhead, operating, and capital costs per barrel of production. Our organization is focused on this metric and we have linked incentive compensation to it. The metric is designed to drive cost reductions, increase well productivity, optimize base production.

In 2014 our total spend per barrel averaged close to $62. We lowered this to about $40 in 2015 and have targeted $28.50 per barrel in 2016. In the first half of this year we have beaten our target with average total spend of about $27 per barrel. We expect similar results during the second half of this year.

Despite the increase in oil prices and energy costs during the second quarter, we held our production costs flat on a sequential quarterly basis while achieving a year-over-year decline in production costs of approximately 19%.

Maintaining a conservative balance sheet continues to be a focus and top priority. We ended the second quarter with $3.8 billion of cash on hand, an increase of $600 million from the first quarter. Our cash flow from operations exceeded our capital spending in the second quarter and we collected the remaining $300 million of proceeds from our settlement with Ecuador.

Throughout this year we have consistently said that we will prudently manage our activity levels to stay positioned for profitable growth in 2017, while maintaining the flexibility necessary to maneuver through the uncertainty and volatility of this price environment.

The capital redeployed into Permian Resources will be used to add two rigs by the fourth quarter to support production growth in 2017. The incremental capital for Colombia will be around $20 million. It will be directed to activities in La Cira Infantas, where we have a successful partnership with Ecopetrol, to develop low decline water floods. The incremental production from this activity is also intended to support growth in 2017.

Given the short-cycle nature of our Permian Resources business and the flexibility we have in our Colombia operations, we can adjust our capital spending up or down relatively quickly depending on the price environment.

On the M&A front, we also continue to look for ways to expand and further strengthen our position in the Permian through asset acquisitions, as we rarely purchase whole public companies. Our objective is to pursue opportunities in both enhanced oil recovery and in our resources business that provide meaningful synergies to enhance the value of our existing assets. Our goal in acquiring additional EOR assets is to blend development of long-lived, low decline production with our faster growth, unconventional development.

While we continue to evaluate potential opportunities, we are staying return focused and note that asset prices appear excessive when one considers the current product price environment.

At our Board meeting in July we announced a modest increase in our annual dividend rate from $3 to $3.04. We have now increased our dividend every year for 14 consecutive years and a total of 15 times during that period. The dividend increase reflects our commitment to shareholders to grow the dividend annually, as is consistent with our long-standing capital priorities.

As a reminder, our top priority for use of cash flow is the safety and maintenance of our operations. Our second priority is to fund the dividend. With improved capital efficiency in our Permian Resources business, the start up of the ethylene cracker in chemicals, combined with long-lived base production and a portfolio of high-quality opportunities, we expect continued future dividend growth.

I am pleased to note that our Board of Directors has elected a new director, Jack Moore. Jack most recently served as the Chairman and CEO for Cameron International. Prior to joining Cameron, he held various management positions at Baker Hughes and has nearly four decades of experience in the energy sector. His industry knowledge and management experience will be a great addition to our Board.

Before I hand off to Chris, I would like to summarize by pointing out that across all of our upstream oil and gas operations and in OxyChem and in our midstream business our teams are executing efficiently and innovatively to achieve technical and operational excellence in all of our areas. Three things are driving this.

First, the ability to focus on our core areas without the distraction from activities that are not core to us, thanks to the initiatives Steve Chazen started in 2013. Second, we have excellent leadership at all levels throughout our organization. Third, our employees are performing at a very high level. They are engaged, motivated, and delivering exceptional results.

While I am happy about that and the direction we are headed, none of us are satisfied with where we are today, so we will continue to aggressively and innovatively improve our performance.

I will now turn the call over to Chris Stavros for a review of our financial results and detailed guidance.

Thanks, Vicki, and good morning, everyone. Today I will plan to talk about the following: some of the key changes that have occurred since the first quarter, our second-quarter segment and financial results, and our third-quarter and total-year guidance for production and capital.

Index prices for WTI and Brent improved progressively each month and ended the second quarter with about a $12 per barrel increase compared to first-quarter prices. Our income and cash flows benefited from a 35% increase in realized prices for both oil and NGLs. During the second quarter, we received a tax refund of $300 million for the NOL tax receivable booked at year-end 2015 and we collected the remaining payments of $330 million related to the Ecuador settlement.

Our core financial results for the second quarter of 2016 were a loss of $136 million, or $.18 per diluted share. This represents a sequential improvement from the loss of $426 million, or $0.56 per diluted share, during the first quarter. Although commodity prices improved significantly from first-quarter levels, they remain well below the prior-year second quarter.

Second-quarter 2016 reported results for GAAP purposes were also a loss of $0.18 per diluted share, as there were no material non-core items during the period. Oil and gas core pretax results for the second quarter 2016 were a loss of $117 million compared to a loss of $508 million in the first quarter of 2016 and income of $324 million from the same period last year.

The sequential improvement of $390 million was nearly all a result of higher commodity prices. Our second-quarter 2016 worldwide realized oil price of $39.66 per barrel increased by over $10 a barrel, or 35%, compared to the first quarter. Total company oil and gas production volumes from our ongoing operations averaged 609,000 BOE per day in the second quarter, an increase of 19,000 BOE per day on a sequential quarterly basis and 57,000 BOE per day higher than last year's second quarter.

Quarterly production volumes were at the high end of our guidance range of 600,000 to 610,000 BOE per day. International production from ongoing operations was 307,000 BOE per day during the second quarter of 2016 and up 24,000 BOE per day compared to the first quarter as the Al Hosn gas plant completed its scheduled first-quarter warranty shut down and Oman's Block 62 gas project continued to ramp up production.

Second quarter domestic production from ongoing operations of 302,000 BOE per day came in nearly 2% lower than the first quarter. The sequential decline was partially due to the drop in production from the absence of gas-directed drilling activity at our South Texas assets and unplanned plant outages that our non-operated Permian EOR operations.

Compared to the prior-year second quarter, our domestic production was up about 4,000 BOE per day with Permian Resources growing by 17,000 BOE per day, or 16%, partly offset by a decline in natural gas production at our South Texas properties.

Domestic oil and gas cash operating costs from ongoing operations of $11.80 per BOE in the second quarter of 2016 were roughly flat on a sequential basis. However, they declined by 13% compared to the full-year 2015 costs of $13.58 per BOE. The reduction in cost compared to last year is mainly the result of improved efficiency around our surface operations, including water handling, as well as lower downhole maintenance and energy-related costs.

Overall, oil and gas DD&A for the second quarter 2016 was $15 per BOE compared to $15.81 per BOE during 2015. Taxes other than on income, which are directly related to product prices, were $1.12 per BOE for the second quarter of 2016, compared to $1.32 per BOE for the full-year 2015. Second-quarter exploration expense was $27 million.

Chemical second-quarter 2016 pretax core earnings were $88 million, compared with first-quarter earnings of $126 million. The sequential quarterly decline in core earnings reflected lower chloro vinyl production volumes due primarily to scheduled plant outages, partially offset by more favorable vinyl margins.

Midstream pretax core results were a loss of $58 million for the second quarter of 2016, compared to a loss of $95 million in the first quarter. The sequential improvement reflected better oil and gas marketing margins and stronger domestic gas processing results due to higher NGL prices. Midstream also realized higher income from its domestic pipeline business, as well as sequentially higher third-party foreign pipeline revenues as the Dolphin gas plant was down for planned maintenance in the first quarter.

Looking at our cash flows for the second quarter, we ended the quarter with $3.8 billion of cash. During the second quarter, we generated $935 million of cash flow from continuing operations before working capital and other changes. Net working capital changes consumed $195 million of cash during the period and we expect working capital changes to be much less burdensome to our cash flow during the second half of the year.

Capital expenditures for the second quarter were about $660 million, bringing our year-to-date capital spending to $1.3 billion. As Vicki mentioned, our capital spending in the second half of the year will increase modestly as certain project-related expenditures in both chemicals and midstream had been deferred into the latter part of the year. In addition, we plan to recycle some of the capital efficiency savings back into our Permian Resources drilling program and also take advantage of some project opportunities in Colombia.

Despite the higher expected capital spending during the second half of the year, our 2016 total company capital program remains on track to be within our original budget of $3 billion. During the second quarter we also completed a $2.75 billion three-tranche senior notes offering with attractive coupon rates of 2.6%, 3.4%, and 4.4% on the six-year, 10-year, and 30-year notes, respectively, and extending the average life of our debt by about five years. The primary use of proceeds went to refinance the $750 million of notes that matured on June 1, 2016, and the early redemption of $1.25 billion of notes that were scheduled to mature in February 2017.

In addition, we also paid $575 million in dividends and collected $330 million in payments, completing the settlement with Ecuador.

With respect to guidance and as Vicki mentioned, we now expect our full-year 2016 production growth from ongoing operations to come in at the high end of the 4% to 6% range. Better-than-expected production volumes achieved during the second quarter, as well as improved confidence around Permian Resources and performance in the Middle East during the second half of the year, allow us to narrow the estimated range of full-year 2016 production from 585,000 to 600,000 BOE per day to a new range of 590,000 to 600,000 BOE per day.

Turning to guidance for the third quarter, we expect our total oil and gas production, pro forma for ongoing operations, to be between 600,000 and 605,000 BOE per day. As I had mentioned during the first-quarter call, we expect production in Permian Resources to decline during the second half of 2016. We anticipate production in Permian Resources to be approximately 116,000 BOE per day in the third quarter.

Variability around the outcome will be a function of well performance, the capture of further efficiency gains, and our ability to manage the base production. Despite the anticipated decline this quarter, we expect our full-year 2016 production in Permian Resources to be approximately 121,000 BOE per day, representing year-over-year growth of 10%.

Our plan is to remain disciplined with our capital within the current product price environment and to recycle some of the efficiency and productivity gains realized this year into greater activity during the second half of the year. We expect this additional activity to help support our Permian Resources production as we exit this year and provide a platform for growth into 2017. Jody will share some specifics on this during his prepared remarks.

We expect our total domestic production to decline about 10,000 BOE per day sequentially in the third quarter, largely due to lower volumes in Permian Resources and partially due to declining natural gas production.

Internationally, third-quarter production should increase by about 6,000 to 8,000 BOE per day mainly driven by the continued ramp up of Oman's Block 62 production.

Our DD&A expense for oil and gas is expected to be approximately $15 per BOE during 2016 and depreciation of the oil and gas segment is expected to exceed this year's capital investment by more than $1 billion. The combined appreciation for chemical and midstream segments should be approximately $655 million.

Exploration expense is estimated to be about $25 million pretax for the third quarter. Price changes at current global prices affect our annual operating cash flow by about $100 million for every dollar-per-barrel change in WTI. A swing of $0.50 per 1 million BTUs in domestic natural gas prices affects annual operating cash flow by about $45 million.

In chemicals, we anticipate pretax earnings of about $130 million for the third quarter as the business ramps back up from second quarter's planned maintenance outages at several of our chloro vinyl plants, combined with improved caustic soda prices. In midstream, we expect the third quarter to generate a pretax loss of between $20 million and $40 million. While quarter-to-quarter changes can be volatile in this segment, the sequential improvement is anticipated due to higher foreign pipeline income and higher income from power generation, as well as improvements in our crude oil supply commitments.

These factors, combined with better results for domestic gas processing, should provide a noticeable improvement in our overall midstream results during the second half of the year compared to the first six months' results. The worldwide effective tax rate on our reported and core income was 41% for the second quarter of 2016. Using current strip prices for oil and gas we expect our 2016 domestic tax rate to be about 40%. Our international tax rate should be about 60%.

I will now turn the call over to Jody Elliott, who will discuss activity around our Permian operations.

Thank you, Chris, and good morning, everyone. Today I will provide a review of our domestic operations during the second quarter and guidance on our program through the end of 2016. As Vicki discussed earlier, we slowed our Permian Resources drilling program as planned due to the severely-depressed product prices in the beginning of 2016. We strategically increased capital spending in the EOR business, which will drive increased production in future quarters and years.

In order to prepare for growth in 2017, we plan to add two drilling rigs in our resources business later this year. We will increase our operated rig count over the second half of the year to seven to eight drilling rigs in the Permian, five of these in Permian Resources. This is an increase from our previous guidance of four to five rigs.

This incremental activity is a direct result of program savings from improved capital and operating efficiencies as well as improvements in base production management. Our team has performed extraordinarily well to capture these savings, which will be reinvested back into the business.

As stated last quarter, our Permian Resources operation is being managed to maximize the value of our workforce, enhance our operational capabilities, invest in areas with existing infrastructure, and gather critical appraisal information to drive better well productivity. Our focus for the remainder of the year is to prepare the business for profitable growth in 2017.

Turning to the performance of Permian Resources, in the second quarter we achieved daily production of 126,000 BOE per day, a 16% increase versus the prior year. Oil production decreased quarter over quarter by 5,000 barrels a day to 79,000 barrels per day; however, this was a 10% increase from a year ago. The decline was due to lower capital spending with 14 wells put online versus 37 wells in the first quarter.

In addition to better performance of our wells, emphasis on production optimization has been central to reducing declines in the business and we have exceeded our expectations versus our goals. As previously stated, we expect to increase our activity in the second half of 2016 and bring approximately 30 wells online.

Due to the slowdown in activity in the first half of the year due to depressed oil prices and a disciplined development strategy, we expect to see declines in the third and fourth quarter. Third-quarter production should average 116,000 BOE per day. For the full-year of 2016 we expect to produce 121,000 BOE per day, a 10% growth rate year over year. As our activity increases we expect production declined to stabilize and, with higher oil prices, we will deliver production growth in 2017.

As we continue to increase our lateral lengths, we now compare and benchmark our well cost on a cost per 1,000 feet of lateral length basis. Slide 31 illustrates our demonstrated improvement in well costs, which have declined by roughly 30% from 2015. Similarly, our 1,000 foot of lateral per rig per quarter has also improved from 25.2 per rig in 2015 to 36.3 per rig in the second quarter. These metrics will be a primary focus as we continue our development plans.

I would emphasize that we estimate 80% of these improvements in efficiency are not at risk of service price increases in a cyclical recovery.

Our Delaware Basin well performance continues to be strong despite reduced activity. We placed seven horizontal wells on production in the Wolfcamp A benches in the second quarter. We continue to increase well productivity by increasing contact with a reservoir near the well bore utilizing higher cluster density, higher proppant loading, and drilling longer laterals.

For example, we placed three Buzzard State unit wells online with an average peak rate of 1,993 BOE per day and a 30-day rate of 1,733 BOE per day. The HB Morrison B 15H well with a 5,000 foot lateral achieved a peak rate of 2,265 BOE per day and a 30-day rate of 1,717 BOE per day.

As can be seen in the chart on slide 32, well productivity continues to improve across our production metrics year over year due to our successful efforts of applying geologic and reservoir parameters into our landing zones and completion designs. In the Delaware Basin our Wolfcamp A 4,500-foot well cost decreased by about 19% from the 2015 cost of $7.7 million to a first-half 2016 cost of $6.2 million. We reduced our drilling time by six days from the average of 25 days in 2015 to 19 days measured by rig release to rig release.

We expect the cost and productivity improvements in drilling, completions, and facilities to [continue] as we progress our program. In addition, we drilled a second Bonespring appraisal well in the Texas Delaware region with encouraging results, which we believe will add additional bench potential to the long-term development plan in this area.

We did not put any additional wells online during the second quarter in New Mexico, though we were actively drilling in the region. However, our second Bonespring 180-day cumulative production rates are among the best in the play. During the second half of the year we plan to increase drilling and completion activity in the southern Eddy County area due to these improved results. We are targeting an average well cost of $5.5 million and we continue to appraise and delineate multiple benches in the core areas of this region. And our initial results have indicated high-return, multi-bench development potential.

In the East Midland Basin we brought on the Waldron Eunice 1306WA well in the second quarter at a peak rate of 1407 BOE per day and a 30-day rate of 1,286 BOE per day. We also brought online the Merchant 1404A well at a peak rate of 1,222 BOE per day and a 30-day rate of 1,061 BOE per day. Both wells are producing with high oil cuts.

In the West Midland Basin, eight new Lower Spraberry wells out South Curtis Ranch are producing results among the best in the play. Improved well results are due to an optimized landing zone target and stimulation redesign.

In the Midland Basin, we made similar improvements in well cost and drilling days in drilling the Wolfcamp A formation. We reduced the cost of these 7,500-foot horizontal wells by 10%, from the 2015 cost of $7.1 million to a first-half cost of $6.4 million, including the additional cost of increased frac size. We reduced our drilling time by three days from the 2015 average of 19 days to 16 days measured by rig release to rig release.

In the Permian Resources as a whole, we achieved another quarter of lower quarter-over-quarter field operating expenses, due mainly to improved service operations with optimized water handling, lower workover expenses, and better downhole performance. Since the second quarter of 2015 we've reduced our operating cost per barrel by 27%, continue to work additional cost reduction and efficiency improvements.

As stated earlier, our focus on maximizing production from existing wells has been central to reducing declines in the business. We expect that our annual average uplift from our investment will be over 6,000 net BOE per day. This is another example of leveraging our decades of base management expertise in the EOR business to our resources business.

In addition to the Midland Basin and Delaware Basin results, we drilled and completed two horizontal Wichita Albany appraisal wells on existing HBP acreage on the Central Basin Platform. We are encouraged by the early results of these lower decline rate wells and would anticipate drilling six to eight follow-up wells in the play in the next 12 to 18 months.

In Permian EOR we continue to take advantage of lower drilling costs and manage the operations to run our gas processing facilities at full capacity. Permian EOR had another quarter of free cash flow generation driven by resilient base production and low capital requirements. Drilling costs are running 23% below our benchmark target and we've lowered our cash operating expenses by 20% since the fourth quarter of 2014 and 7% year over year, driven mainly by lower downhole maintenance and injectant costs.

In similar fashion to our resources business, the capital savings achieved by the EOR team will be reinvested into additional wells and CO2 flood expansions. As I have mentioned in previous calls, the residual oil zone development, or ROZ, is a vertical expansion of the CO2 flooded interval. The ROZ underlies most of our major EOR properties and can be developed between $3 and $7 a barrel.

Year to date we have completed 74 well deepenings and recompletions along with 28 new wells and ROZ developments. We anticipate an additional 30 deepenings and recompletions and 22 new wells and ROZ developments in the second half of 2016. In addition, one of our horizontal rigs from Permian Resources drilled two deep CO2 sourced wells, which will help provide long-term supplies of CO2 and support our vast inventory of EOR development projects.

In summary, we are achieving better-than-expected results in both Permian businesses that will allow us to invest the savings into additional wells to each respective business. In the current environment we believe this is a prudent investment philosophy that motivates our employees and works well with our total spend per barrel incentive metric. We are pleased with the strides our teams have made in execution, performance, and safety this far in 2016, which will afford us the ability to ramp up our activity should oil prices exhibit fundamental stability.

Thank you. I will now hand it back to Chris Degner.

Thank you, Jody. We will now open up the call for questions. We would ask that you please limit your questions to just one and then a follow-up.

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

Thanks. Good morning, everybody. Vicki, adding a couple of rigs to the Permian in the back end of this year; I'm just curious when you talk about priorities for the use of cash, ultimately where do you see that activity going? Is it a maximum -- you have talked in the past about the proportion of growth that you would want from the Permian at least to be limited in terms of not impacting your dividend policy. But is there a kind of run rate that would expect to be a normalized run rate as you start to add activity back given the deep inventory?

You are talking about run rate with respect to rig activity?

Yes, and capital expenditure. Is there a limit as to how much you would want to allocate there? Because obviously in a rising oil price environment you guys have got a lot of levers you could pull.

Right. Currently for at least next year in 2017 -- and it is hard to predict for 2018 -- but for 2017 we intend to stay pretty close to the capital allocation that we have for this year. And that is assuming that prices are as we expect. I will say that we kind of expected the prices to be in the neighborhood of where they are right now and that is why we took a conservative approach to our capital this year.

We do expect some improvement next year, but we are not sure how much that will be so we're going to wait till toward the end of this year to determine exactly what our capital program for 2017 will be. But our expectation is that, if things are as we expect them to be, that we would be close to $3 billion. We might spend a little bit more than that if prices are a little bit better than we expect, but the run rate for our company going forward with the assets that we currently have would continue to be in the $3 billion to $3.5 billion. Maybe a little bit more, but not a whole lot more, than that.

Maybe just a quick follow-up to that. Perhaps a better way to address the question, Vicki, is what is the operating capacity that you have in the Permian? Do you have a lot of headroom where you could add rigs without necessarily having to increase capability?

We have the capacity to increase significantly. We will be more limited by our disciplined approach, but we certainly have kept the capability within our organization. We have the ability to put the infrastructure in the Permian, so we have, I would say, significant ability.

At one time we were running over 25 rigs and we could, if prices were in the range that would warrant that, we could get back to that. But bearing in mind now that back when we were running 25 rigs, we were not as efficient as we are today. We are significantly improved with our efficiencies so we could get actually the same amount of productivity with half the number of rigs that we were at, at that time.

So I don't see us going back to a 25 rig count in the Permian, unless we expand our operations and our footprint. But we could easily go back to somewhere in the neighborhood of up to 15 rigs reasonably and still have the capacity to do it. I think we could get ahead of it with our infrastructure as well.

Actually Jody could talk a little bit more, if you would like, about the infrastructure development and how we are trying to stay ahead of it. He has got teams working on development plans for our key areas that will put us, we believe, well ahead so that we could ramp up to levels of that activity without being encumbered by regulatory issues and/or infrastructure issues.

My follow-up, Vicki -- I don't want to take up too much time here. My follow-up is a bit of an obtuse question and I apologize in advance.

The use of cash, the priority for use of cash, acquisitions is still at the bottom of that list and your commentary in the slide deck again pointed to a fairly bid-ask spread as it relates to CO2. However, your currency is also quite valuable. So I'm just wondering should we be thinking a little bit out of the box in terms of whether Oxy would be prepared to use equity to make a CO2 add to the portfolio.

And I will leave it there. Thanks.

I will say that the way you should view the capital priorities right now is just the two that I mentioned. Certainly, maintenance of our operations is the highest priority; dividends is second. But when you look at the other possibilities, whether it is organic growth or share repurchases or acquisitions, those three really depend on the situations that we are in. And so those three can vary over time or according to the environment that we are in.

I would say that for today, as per my comments about M&A, we are certainly looking at acquiring assets and expanding our position in the Permian and we would be, for the right project, for the right opportunity, certainly be willing to use our equity to do that.

Appreciate the answer. Thanks, Vicki.

Phil Gresh, JPMorgan.

Good morning. First question is just maybe following up on your commentary about capital spending for 2017. How would you kind of tie that spending to what kind of growth you think you could achieve across the portfolio, factoring in that Permian Resources will be declining and kind of leveling off in the fourth quarter? And I'm thinking not only in Permian Resources, but also internationally when you think about the growth that you are seeing out of Oman and what you talked about with Al Hosn.

I would say that with the future of the way we view it and what we expect to see in 2017, we are going to try to achieve within our range of growth targets but probably, possibly on the lower end, if prices are still on the lower end and we don't see fundamentals driving prices up. So we are going to wait pretty much till the end of this year to make final decisions on it.

But we do believe that in a price environment that is certainly better than where we are today is what we would need to continue to grow. But Permian Resources, we will grow Permian Resources next year. The question for us is whether or not we will grow other areas within our company for next year and that will all depend on what oil prices do.

And just to clarify, the historical range that you are referring to --?

The historical range is 4% to 6%.

Okay. So you still think you can hit the low end of that range next year?

We do in the price range that we would expect.

Got it, okay. And of that $3 billion, I know you gave this number a couple quarters ago, but what do you think is your sustaining capital requirement at this point for the total company?

I'm sorry, you cut out. Could you ask that question again?

What do you think the sustaining capital requirement is for the total company at this point? I know you gave that number a couple of quarters ago in your slides, curious if the view is the same or if that has changed at all.

The increased production that we have now, the capital that would be required to offset declines would be in the neighborhood of about $2.3 billion to $2.4 billion.

Got it. Okay, thank you. I will turn it over.

Ed Westlake, Credit Suisse.

I guess the first question is just on that sort of production outlook for 2017, very helpful. Given the improvement in the D&C days and the well performance I guess and the investments in EOR, I would have expected 2017 to be perhaps a little bit stronger than that. So maybe just talk through it; timing of when you complete the wells, pad drilling type stuff.

It is a lot more around the uncertainty of the price environment and it has a lot less to do with our capability to do it. What we want to do is ensure that we are conservative with our capital programs. We have the potential and the opportunities to certainly not only meet the upper end, but exceed it, but we're really trying to be careful about what we forecast and what programs we set up for next year.

I can tell you that what we will do is that we will put the program together -- we always do that at the end of this year -- and we will firm it up by first of next year. But what our teams have done during this downturn is this slower period is they've enabled us to have a lot more flexibility next year to be able to ramp up should we need to or should we have the opportunity to do so.

And the ramp up could be not just in Permian Resources. As I mentioned earlier, the ramp up could be in Colombia as well. And in addition to that, we expect that because of the situation with Al Hosn, overall Al Hosn will have a higher production rate in 2017 because it will have a full year of production versus the warranty turnaround that we had in Q1 of this year. In addition to that we will have Block 62 gas on for the full year and that will be helpful.

So you take those things, combine it with the flexibility that we have in both Permian Resources and Colombia, we will start the year probably conservatively until we see fundamentals start to support prices. But we will have the ability to ramp up in multiple areas. If prices and the fundamentals are such that we feel comfortable, we will have the flexibility to actually increase our programs throughout the year if we see that that makes sense.

Second question is on a sort of Bone Springs chart that you have got in here on page 34, just with a new design: 4,500-foot lateral, 180 day cumulatives over 200, and a decent oil cut. I mean that actually looks a bit better than the chart you have got here on page 36 for a 10,000-foot lateral in the lower Spraberry.

So I guess the question is: is this -- and I think I've asked this before -- really a sweet spot in the Bonesprings geology or --? Really maybe just give us some color as to how optimistic you feel about the Southeast New Mexico asset.

Ed, this is Jody. Good morning. It is more than a sweet spot. I think we are encouraged with Southeast New Mexico across the board. Multiple bench development, these examples are over in our Cedar Canyon area but further east of that area there is acreage with even more benches that are prospective. So very encouraged with Southeast New Mexico and the rig adds that we're talking about will likely be in the Delaware and in New Mexico.

Okay. Thanks very much. Well done.

Ryan Todd, Deutsche Bank.

Great, thanks. Maybe a couple. One, in regards to 2017 capital, can you talk about what you believe the year-on-year change in cash balance is driven by the chemicals business? For example, how much capital you see rolling off into 2017 relative to incremental cash flow from the start-up of the cracker.

Yes, for the chemicals cash flow we expect that capital this year is around $500 million. Next year it should drop to less than $400 million. The following year it would be back down to basically its maintenance levels of around $250 million. So we will have around $300 million cash flow from chemicals this year and expect that by 2018 that would be up to around $900 million, potentially a little bit more than that depending on product prices in the chemical business.

Okay. So that should free up significant capital I guess into 2017 to be -- even in that $3 billion world -- to be reinvested back into the organic upstream business?

That is correct. We had about -- total, including the chemicals and the midstream business, we had this year $500 million of committed capital and almost $400 million of that is coming off for 2017. That will be redeployed into -- most of that into the Permian Resources business.

Perfect, thanks. Then maybe just one follow-up on portfolio rationalizations. At this point you guys have been very active over the last 12 to 18 months. Is it all done? Is there anything left to be done in terms of streamlining the portfolio?

And I am not sure if you mentioned this in the prior comments, if I missed it; within that regard, PAGP, what would you need to see to further monetize that?

Most of the rationalization in terms of oil and gas, and certainly Middle East operations, is largely behind us. We have done that over the last year or so.

From a corporate asset perspective, we still have, as you point out, the Plains units. There is about 80 million units of that and they've just gone through their simplification process, so we will let that sort of close out here formally in the latter part of the year, fourth quarter with their plan.

This is not a strategic investment on our part, so I would tell you that we don't look to hold on to that longer term. So that is sort of an option in terms of liquidity that we have got. Market value is sort of $800 million, thereabouts.

Okay, thank you.

Paul Sankey, Wolfe Research.

Vicki, you keep talking about the oil price you are assuming, I assume that that is $50-ish. Previously you had said that you would add rigs once you became confident that $50 would be sustained along the strip. I assume that you are maintaining a kind of view that $50-plus is what we are going to see and, hence, you want to accelerate.

That is pretty close to right. We do expect it to be $50 or above in 2017, but we are not -- certainly we are not as bullish as some people. We are taking, as I said, a conservative view, but it would be fundamentally above $50.

Yes. And, hence, the minor acceleration, I guess we will call it?

Right.

On the Permian deal, I think you have said very clearly you don't want to make a corporate acquisition. I think you need something material to make it worth your while and my sense is that the recent $1 billion type asset packages would not really be of a sufficient scale for you guys to really work the CO2 business in the way that you want to.

Well, the way we view it is the Permian, as you know, it is a huge place. There is lots of opportunities. We are looking at this as a goal and objective in terms of our total expansion and there are multiple ways to get there.

We could get there with several different options. What we have done is prioritized our options and we are working pretty much a lot of things to try to ensure that we reach our goals. But we're happy to (multiple speakers).

I was going to ask you what are -- can you just specify what the goals are?

The goals are to try to match what our growth profile could be in EOR with resources. And we haven't really put what that means in terms of the exact production volumes or anything like that out there, because it is kind of hard to do at this point with respect to the EOR business.

But we are really -- we are in a position, because of where our operations are with respect to EOR in the Permian, we have got the ability in multiple areas to play sort of a Pac-Man approach where we can acquire a lot of smaller assets that could total up to make a material difference to us as a cumulative acquisition. So we are not opposed to looking at a variety of smaller deals. Again, because of our position we would have the capability to do that and make it still fit within our goals to try to make sure that these are synergistic with our current operations.

And then on the CO2 side?

That is actually what I'm talking about. We are going to do the same thing in both resources and CO2, because we have the ability around the areas that we currently operate to add additional properties.

Okay, so what you are saying is on either side you could go smaller or larger, basically, in terms of adding assets? Is that something (multiple speakers)?

That's correct.

I think you are more or less saying that you feel it is necessary if you are going to maintain the scale of growth that you are aiming for.

Yes, the scale of growth is much easier in the resources business. In the EOR business the issue that we have today is that we are constrained by some of our infrastructure. So we feel like some of the expanding to our footprint would enable us to also expand our infrastructure to support some growth, accelerated growth, with not only what we have but what we could potentially pick up.

Right. I think just finally from me just you are somewhat short, I think if not short, depending on your growth plans of CO2 itself?

Currently we don't see an issue with the CO2 that we would need to accelerate growth. We are trying to look at options for where we get the CO2, but I don't see that being a bottleneck for us. I see the current bottleneck being just the fact that it doesn't make sense to accelerate some of our floods where our plants are sized more appropriately for a full field development. So that is really some of the bottleneck, is the infrastructure around the existing plants.

Thank you very much.

Guy Baber, Simmons.

Good morning, everybody. Thanks for taking my question. I wanted to start off with the Permian unconventional production trajectory, but --. You referenced improved confidence in that business in the prepared remarks, but it looks like the guidance today calls for a bigger decline over the back half of the year than we would have expected, down 10,000 barrels a day 3Q.

Can you talk a little bit more about the declines you are seeing there? How conservative that guidance might be; just how that is shaping up?

And then, secondly, in the Permian also, you talked about year-on-year growth for unconventional in 2017. Can you talk about the spending level necessary relative to your $700 million or so budget this year that would be required to deliver production north of 120,000 barrels a day, as indicated in the slides?

Guy, this is Jody. I appreciate the question. With regard to the decline, it is really a function of the activity set from this last quarter. As one of the things I discussed, we have moved a rig and drilled a couple of Wichita Albany wells; we drilled a couple of CO2 source wells. So the activity set in this quarter was fairly low for Resources, which is indicative in the forecast for the third quarter.

But in the back half of the year those rigs are backend resources; we are going to add rigs. And so we will flatten that decline toward the end of the year and then set us up with the right trajectory for production growth into 2017.

Okay, great. Then did you have a spending estimate relative to the $700 million budget this year that would drive north of 120,000 barrels a day of production next year?

We expect that would probably be in the $1.3 billion to $1.4 billion range, but with the way the teams are still improving the efficiencies and the well productivities are getting better, we are not prepared to commit to that completely at this point. Every time we set a target for those guys they meet or exceed it, so we are not sure that that is the exact number. We will know better about that by the end of the year as we prepare our final plans and we get a little more information from our Southeast New Mexico developments.

That is very helpful. Then I wanted to ask one on Al Hosn. But obviously very strong performance during the quarter, above nameplate capacity. Can you talk a little bit more about what drove that?

Is that type of performance sustainable? And are you already finding ways to kind of sustainably I guess debottleneck that production in the next year?

Guy, this is Sandy Lowe. Good question. As we do with other large facilities like this, we tend to -- when everything is stable, we tend to test individual components and processes within the plant. We have been doing that during the summer, which is the toughest time, the most relevant proving because of the relatively high heat in the area. And we have been able to show our guidance for 60,000 barrels a day equivalent for Oxy share.

We have been up in the high 60,000s with the promise to get into the 70,000s just by pushing individual processes pretty hard. The main reason for this is to assess what the expansion would look like and which components would need either total addition or enhancement or some that might just be able to take higher load.

So we think out of this will come, if you like, a new baseline which could be 110%, 112%, or even a bit higher, and from there we would design an expansion to get up to a good number, kind of the sweet spot for the investment profile and the production profile. Of course, working with our bigger partner, the Abu Dhabi National Oil Company.

So that is kind of where we are with it. I think it will be -- the fact that we did this during the summer is probably pretty good for you around enhanced production.

Thank you very much.

Roger Read, Wells Fargo.

Thanks, good morning. I guess to jump into the Permian area; I was wondering, with some of the areas you have expanded into, specifically in Southeast New Mexico and your discussion of additional benches. Is part of the rig count increase reflective of any kind of an HBP issue arising here or is all the acreage fairly well secure and just simply reflects kind of your -- like you said, the price outlook and budgetary expectations?

Roger, most of our acreage is HBP. We have some drilling clocks, 180 drilling clocks, but the activity set is driven by the value proposition and the returns from these investments. We have very few remaining lease obligation drilling wells, if any at all.

Okay, thanks. Then I am not sure if this is for you, Jody, or for Vicki, but the way to think about the drilling efficiencies that you have achieved. If we essentially kind of quadruple from the drilling level we have been or double from the year-end exit rate, the 15 rigs that were mentioned, what would you think of budgetarily or operationally as the right way to think about those efficiencies? It can continue to be realized or do we see the curve kind of bend the other way?

And this is not specifically looking at you, but as we add that many rigs we are going to get some less efficient crews potentially into the field. And I am just trying to understand, on a longer-term basis, what that may mean for well costs, breakevens, cash flow, and all.

I think that is manageable as long as the ramp up, from an industry perspective, is fairly moderate. What encourages me, at least for us at Oxy, is that we continue to have new ideas coming forward for cost efficiency.

We mentioned before last year we had this cost stand down day. In Resources alone that generated over 1,400 ideas. We have put in place about half of those and so we are still vetting the other half for opportunities. Again, that crosses OpEx, capital, SG&A.

We have some other technology things we are working on the drilling side that we think can provide efficiency gains. We know at some point that the price cycle will turn around on services, but I think we are getting well-prepared to offset that with efficiency. Not just for us, but for the supplier as well in areas of integrated planning and logistics, crew utilization, equipment utilization, bundling of services.

There is just a number of things that we think can help offset the potential for either efficiency or cost pressure as we move forward. So I think we can hold those kind of rates of return.

And if I could sneak in one more along those lines of efficiencies. As we think about the additional rigs in the fourth quarter, what is roughly the time from sort of adding that rig, say, spud date to first oil production? It sounds like you are pretty far ahead on the infrastructure side, so I would think pretty quick tie-ins.

It is fairly quick. It is really more a function as a single well or is it a multi-well pad where you want to drill all the wells and then complete all the wells? So your time to market for that package is a little bit longer. But, again, we are drilling in areas mostly where we have got infrastructure and so adding wells is fairly quick. There is not a long delay.

Okay, thank you.

I would add to that the way they are doing the developments now is they are doing pad drilling, so as Jody mentioned, the pad drilling will result in lumpy production. That is why we are not expecting production impact from the increased activity levels this year, but we do expect it to show up in early Q1.

And that is why we set the program up that way. It was really a part of our plan to start getting ready for 2017 production, so that is when we will see the incremental from the increased activity.

John Herrlin, Societe Generale.

Thanks. With your Permian acreage, what is the chance of you doing swaps? Then my other question is with Colombia. What would be response time be for the water floods once you get going?

I will start with Colombia first and then we will let Jody take the Permian question. In Colombia what we have done, we entered into -- we currently have a water flood going there now that is successful. We got some additional intervals within that same area to develop two other zones and we have been studying and putting the water flood pilot plans together, so we will be starting the pilot first.

And then -- so that is why we are adding the $20 million there to Colombia is to do the pilot so that we can get some information from that before we start into full field development. The full field development of those water floods will come after we complete the pilot.

John, with regard to the Permian acreage swaps, that is probably our most active area right now with our land business. And so most operators are wanting to drill longer laterals, 7,500, 10,000 foot, and so acreage swaps, especially where you have got more neighboring acreage -- trying to swap Midland for Delaware is a little tougher. But in a general geographic area we are seeing quite a bit of activity and we have taken advantage of that so that we can drill longer laterals.

Okay, thanks. Vicki, back to Colombia, again what kind of response time? A year, six months? Do you have a sense?

I think we would expect that from the time that we start water injection that it would be within the six months to a year.

Okay, thank you.

This concludes our call today. I will now turn the call back over to Chris Degner.

Thank you, Laura, and thank you, everyone, for participating on our call. Bye.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.